NERC Petition for MOD-001-2

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

North American Electric Reliability
Corporation

)
)

Docket No. _______

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD MOD-001-2 AND
RETIREMENT OF RELIABILITY STANDARDS MOD-001-1a, MOD-004-1, MOD-0081, MOD-028-2, MOD-029-1a AND MOD-030-2

Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile

Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
S. Shamai Elstein
Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric
Reliability Corporation

February 10, 2014

TABLE OF CONTENTS
I.

EXECUTIVE SUMMARY .................................................................................................... 2

II.

NOTICES AND COMMUNICATIONS ................................................................................ 7

III. BACKGROUND .................................................................................................................... 7
A.

Regulatory Framework ..................................................................................................... 7

B.

NERC Reliability Standards Development Procedure ..................................................... 8

C.

History of the Existing MOD A Standards and Project 2012-05 ATC Revisions ........... 9
1.

Development of the Existing MOD A Standards ......................................................... 9

2.

History of Project 2012-05 ATC Revisions ............................................................... 12

IV. JUSTIFICATION FOR APPROVAL................................................................................... 13
A.

Reliability Issues Associated with ATC and AFC Determinations ............................... 14

B.
Proposed MOD-001-2 Comprehensively Addresses the Reliability Issues Associated
with ATC and AFC Determinations ......................................................................................... 17

V.

C.

Proposed MOD-001-2 Satisfies Outstanding Commission Directives .......................... 28

D.

Enforceability of Proposed MOD-001-2 ........................................................................ 37
EFFECTIVE DATE .............................................................................................................. 38

VI. CONCLUSION ..................................................................................................................... 39

Exhibit A

Proposed Reliability Standard

Exhibit B

Implementation Plan

Exhibit C

Order No. 672 Criteria

Exhibit D

Mapping Document

Exhibit E

Consideration of Directives

Exhibit F

Analysis of Violation Risk Factors and Violation Security Levels

Exhibit G

Summary of Development History and Complete Record of Development

Exhibit H

Standard Drafting Team Roster for Project 2012-05 ATC Revisions

i

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
North American Electric Reliability
Corporation

)
)

Docket No. _______

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED RELIABILITY STANDARD MOD-001-2 AND
RETIREMENT OF RELIABILITY STANDARDS MOD-001-1a, MOD-004-1, MOD-0081, MOD-028-2, MOD-029-1a AND MOD-030-2
Pursuant to Section 215(d)(1) of the Federal Power Act (“FPA”) 1 and Section 39.5 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”),2 the North
American Electric Reliability Corporation (“NERC”) 3 hereby submits proposed Reliability
Standard MOD-001-2 for Commission approval. NERC requests that the Commission approve
proposed Reliability Standard MOD-001-2 (Exhibit A) as just, reasonable, not unduly
discriminatory or preferential, and in the public interest. 4 NERC also requests approval of (i) the
associated implementation plan (Exhibit B); (ii) the associated Violation Risk Factors (“VRFs”)
and Violation Severity Levels (“VSLs”) (Exhibits A and F); and (iii) the proposed retirement of
the currently effective Reliability Standards MOD-001-1a, MOD-004-1, MOD-008-1, MOD-0282, MOD-029-1a and MOD-030-2 (the “ Existing MOD A Standards”), as detailed in this petition.

1

16 U.S.C. § 824o (2006).

2

18 C.F.R. § 39.5 (2013).

The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the FPA on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶ 61,062 (2006) (“ERO
Certification Order”).
3

4

Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards, available at http://www.nerc.com/files/Glossary_of_Terms.pdf

1

As required by Section 39.5(a)5 of the Commission’s regulations, this petition presents the
technical basis and purpose of proposed Reliability Standard MOD-001-2, a summary of the
development history (Exhibit G), and a demonstration that the proposed Reliability Standard meets
the criteria identified by the Commission in Order No. 6726 (Exhibit C). The NERC Board of
Trustees approved proposed Reliability Standard MOD-001-2 and the retirement of the Existing
MOD A Standards on February 6, 2014.
I.

EXECUTIVE SUMMARY
The proposed Reliability Standard is designed to replace, consolidate and improve upon

the Existing MOD A Standards in addressing the reliability issues associated with determinations
of Available Transfer Capability (“ATC”) and Available Flowgate Capability (“AFC”). As
discussed below, ATC and AFC values are commercial in nature, representing the amount of
unused transmission capacity that a Transmission Service Provider is willing to make available for
sale to third parties to accommodate additional requests for transmission service. The purpose of
proposed MOD-001-2 is to help ensure that determinations of ATC and AFC are accomplished in
a manner that supports the reliable operation of the Bulk-Power System.
ATC and AFC values derive from the Commission’s open access policies designed to
develop non-discriminatory wholesale electricity markets, including a non-discriminatory market
for the sale of unused transmission capacity. ATC and AFC represent two different approaches
for estimating the amount of transfer capability that could be available for sale for a particular
period of time. ATC measures the transfer capability remaining on a path between two systems

5

18 C.F.R. § 39.5(a) (2013).

6

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, at P 262, 321-37, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).

2

for further commercial activity over and above already committed uses, and AFC measures the
flow capability remaining on a Flowgate for further commercial activity over and above already
committed uses. As defined in the NERC Glossary, ATC and AFC values are determined using
the following equations: (1) ATC equals Total Transfer Capability (“TTC”) less Existing
Transmission Commitments (“ETC”), less a Capacity Benefit Margin (“CBM”), less a
Transmission Reliability Margin (“TRM”), plus postbacks7 and counterflows; and (2) AFC equals
Total Flowgate Capability (“TFC”) less ETC, less a CBM, less a TRM, plus postbacks and
counterflows, where:






TTC represents the total amount of power that can be moved or transferred on a path
between two systems;
TFC represents the maximum flow capability on a particular Flowgate;
ETC represents committed uses of a Transmission Service Provider’s transmission
system, including retail customer service, for the applicable period;
CBM represents the amount of transmission capacity that needs to be set aside for Load
Serving Entities (“LSEs”) to meet certain generation reliability requirements; and
TRM represents the amount of transmission capacity that needs to be set aside to establish
margins for system reliability.
ATC and AFC are commercial values that do not directly control the reliable operation of

the Bulk-Power System. Nevertheless, there are reliability considerations associated with ATC
and AFC determinations. As explained further below, ATC and AFC values have the potential to
influence Real-time conditions on the Bulk-Power System and impact Real-time operations. In
general, as more ATC/AFC is posted, sold and scheduled in Real-time, the transmission system is
closer to exceeding its reliable operating limits. If a Transmission Service Provider overestimates
ATC or AFC and, in turn, sells more transmission service than is actually available, it could result
in a potential or actual violation of System Operating Limits on its system or a neighbor’s system,

7

Postbacks are adjustments to ATC or AFC to account for, among other things, processing of redirects and
unscheduled service.

3

triggering the need for Transmission Operators to take corrective action to maintain system
reliability.
To reduce the potential for oversold condition and make it easier for Transmission
Operators to reliably operate their systems within System Operating Limits, it is necessary to: (1)
account for system limits (e.g., facility ratings, system voltage limits, transient stability limits,
voltage stability limits, or other System Operating Limits) and relevant system conditions (e.g.,
load forecasts, transmission constraints, expected outages) when determining ATC/AFC; and (2)
establish a framework whereby ATC/AFC determinations are made in a transparent fashion so that
planners and operators of the Bulk-Power System maintain awareness of available transmission
system capability and future flows on their own systems as well as pertinent neighboring systems.
The Existing MOD A Standards, established in response to Commission Order Nos. 8908
and 693 9 and approved in Order No. 729, 10 seek to address these reliability concerns by
standardizing the manner in which ATC/AFC is determined and requiring the documentation and
sharing of ATC/AFC methodologies. The Existing MOD A Standards, however, include a number
of requirements that are not necessary to address Bulk-Power System reliability and provide little
to no reliability benefit. Certain existing requirements reflect commercial or business practices

8

Preventing Undue Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12266
(Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007), order on reh'g, Order No. 890-A, 73 FR 2984 (Jan. 16,
2008), FERC Stats. & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 890-B, 123 FERC ¶ 61,299 (2008), order
on reh’g, Order No. 890-C, 126 FERC ¶ 61,228 (2009).
9

Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416, PP 1020-1126
(2007), FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).
10

Mandatory Reliability Standards for the Calculation of Available Transfer Capability, Capacity Benefit
Margins, Transmission Reliability Margins, Total Transfer Capability, and Existing Transmission Commitments and
Mandatory Reliability Standards for the Bulk-Power System, Order No. 729, 129 FERC ¶ 61,155 (2009), order on
clarification, Order No. 729-A, 131 FERC ¶ 61,109, order on reh’g and reconsideration, Order No. 729-B, 132
FERC ¶ 61,027 (2010). Reliability Standard MOD-028-1, which was approved in Order No. 729, was recently
replaced by Reliability Standard MOD-028-2. Revisions to Modeling, Data, and Analysis Reliability Standard, 144
FERC ¶ 61,027 (2013).

4

that address market-related concerns regarding the potential for undue discrimination.

For

instance, the Existing MOD A Standards prohibit Transmission Service Providers from making
transmission capability available on a more conservative basis for commercial purposes than what
is made available for either planning for native load or use in actual operations. This requirement
is not reliability-based; it addresses the market-based concern regarding the potential for differing
treatment of native load customers and transmission service customers. Similarly, the Existing
MOD A Standards prescribe in detail the three methodologies that Transmission Service Providers
and Transmission Operators may use to determine ATC/AFC. This specificity is not necessary
from a reliability perspective. As explained further below, if an entity fails to follow one of those
three methods, it would not necessarily impact reliability.
Proposed MOD-001-2 is designed to replace the six Existing MOD A Standards to
exclusively focus on the reliability aspects of ATC and AFC determinations. This approach is
consistent with the ERO’s expertise and primary mission to develop and enforce standards that
support the reliable operation of the Bulk-Power System. It is also consistent with Commission
orders supporting (1) the removal of requirements from NERC’s Reliability Standards that provide
little protection for Bulk-Power System reliability, and (2) the modification of Reliability
Standards to increase the efficiency of the ERO compliance program.11
Proposed MOD-001-2 contains six requirements that improve upon the reliability-related
elements of the Existing MOD A Standards. The proposed Reliability Standard requires that: (1)
determinations of TTC/TFC and ATC/AFC account for applicable system limits and relevant
system conditions (Requirements R1 and R2); (2) an entity’s ATC, AFC, TTC, TFC, CBM and

11

See Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC
¶ 61,147 (2013); North American Electric Reliability Corp., 138 FERC ¶ 61,193, at P 81, order on reh’g and
clarification, 139 FERC ¶ 61,168 (2012).

5

TRM methodologies are documented and available to other entities (Requirements R1-R5); (3)
registered entities with a reliability need to do so have an opportunity to request that a Transmission
Service Provider or Transmission Operator clarify its methodologies (Requirement R5); and (4)
data underlying determinations of ATC, AFC, TTC, TFC, CBM and TRM are available to other
Transmission Service Providers and Transmission Operators for use in their own determinations
of such values (Requirement R6). Proposed MOD-001-2 also addresses Commission directives
from Order No. 729.
While the proposed Reliability Standard does not retain those elements from the Existing
MOD A Standards that are not necessary for reliability purposes, NERC and the standard drafting
team for proposed MOD-001-2 recognize that certain of those elements may be essential for
market or commercial purposes and should be considered by an organization, like the North
American Energy Standards Board (“NAESB”), that administer business practice standards for the

electric industry. As discussed further below, NERC is working with NAESB to explain the
revised approach to the Existing MOD A Standards and provide NAESB an opportunity to
consider, through its standards development process, which elements of the Existing MOD A
Standards, if any, should be incorporated into NAESB’s Wholesale Electric Quadrant Standards
for Business Practices and Communication Protocols for Public Utilities (the “WEQ Standards”).
The proposed Implementation Plan for MOD-001-2 is designed to accommodate NAESB’s
consideration of those elements from the Existing MOD A Standards that relate to commercial or
business practices and are candidates for inclusion into its WEQ Standards.12
For the reasons discussed herein, NERC respectfully requests that the Commission approve
the proposed Reliability Standard and the retirement of the Existing MOD A Standards.

12

To the extent that the proposed implementation period does not provide NAESB sufficient time to consider
the issues, NERC is committed to working with NAESB and Commission staff to address any timing issues.

6

II.

NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the following:13

Charles A. Berardesco*
Senior Vice President and General Counsel
Holly A. Hawkins*
Assistant General Counsel
S. Shamai Elstein*
Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
[email protected]
[email protected]
[email protected]
III.

Mark G. Lauby*
Vice President and Director of Standards
Valerie Agnew*
Director of Standards Development
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
[email protected]
[email protected]

BACKGROUND
A.

Regulatory Framework

By enacting the Energy Policy Act of 2005,14 Congress entrusted the Commission with the
duties of approving and enforcing rules to ensure the reliability of the Nation’s Bulk-Power
System, and with the duties of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1) of
the FPA states that all users, owners, and operators of the Bulk-Power System in the United States
will be subject to Commission-approved Reliability Standards.15 Section 215(d)(5) of the FPA
authorizes the Commission to order the ERO to submit a new or modified Reliability Standard. 16
Section 39.5(a) of the Commission’s regulations requires the ERO to file with the Commission for

Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2013), to allow the inclusion
of more than two persons on the service list in this proceeding.
13

14

16 U.S.C. § 824o (2006).

15

Id. § 824(b)(1).

16

Id. § 824o(d)(5).

7

approval of each Reliability Standard that the ERO proposes should become mandatory and
enforceable in the United States, and each modification to a Reliability Standard that the ERO
proposes should be made effective.17
The Commission has the regulatory responsibility to approve Reliability Standards that
protect the reliability of the Bulk-Power System and to ensure that such Reliability Standards are
just, reasonable, not unduly discriminatory or preferential, and in the public interest. Pursuant to
Section 215(d)(2) of the FPA 18 and Section 39.5(c) 19 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the content
of a Reliability Standard.
B.

NERC Reliability Standards Development Procedure

The proposed Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development process.20 NERC
develops Reliability Standards in accordance with Section 300 (Reliability Standards
Development) of its Rules of Procedure and the NERC Standard Processes Manual.21 In its ERO
Certification Order, the Commission found that NERC’s rules provide for reasonable notice and
opportunity for public comment, due process, openness, and a balance of interests in developing
Reliability Standards and thus satisfies certain of the criteria for approving Reliability Standards.
The development process is open to any person or entity with a legitimate interest in the reliability

17

18 C.F.R. § 39.5(a) (2012).

18

16 U.S.C. § 824o(d)(2).

19

18 C.F.R. § 39.5(c)(1).

20

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
21

The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.

8

of the Bulk-Power System. NERC considers the comments of all stakeholders, and a vote of
stakeholders and the NERC Board of Trustees is required to approve a Reliability Standard before
the Reliability Standard is submitted to the Commission for approval.
C.

History of the Existing MOD A Standards and Project 2012-05 ATC
Revisions
1.

Development of the Existing MOD A Standards

As noted, the Existing MOD A Standards derive from the Commission’s open access
policies designed to develop non-discriminatory wholesale electricity markets. The obligation for
Transmission Service Providers to determine ATC or AFC was first introduced in Order Nos.
888 22 and 889. 23 In seeking to prohibit transmission providers from potentially using their
monopoly power over transmission to unduly discriminate against others, the Commission, among
other things, directed transmission providers to calculate ATC, describe their methodology for
such calculations in an Attachment C to their Open Access Transmission Tariffs (“OATT”), and
post those calculations on their Open Access Same-Time Information Systems. The Commission
concluded that it was “important to give potential transmission customers an easy-to-understand
indicator of service availability.”24

22

Promoting Wholesale Competition Through Open Access Non-discriminatory Transmission Services by
Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR
21540 (May 10, 1996), FERC Stats. & Regs. ¶ 31,036 (1996), order on reh’g, Order No. 888-A, 62 FR 12274 (Mar.
14, 1997), FERC Stats. & Regs. ¶ 31,048 (1997), order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order
on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy
Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002).
23

See Open Access Same-Time Information System (Formerly Real-Time Information Networks) and
Standards of Conduct, Order No. 889, 61 FR 21737 (May 10, 1996), FERC Stats. & Regs. ¶ 31,035 at 31,749
(1996), order on reh’g, Order No. 889-A, FERC Stats. & Regs. ¶ 31,049 (1997), order on reh’g, Order No. 889-B,
81 FERC ¶ 61,253 (1997).
24

Order No. 889, FERC Stats. & Regs. ¶ 31,035 at 31,749.

9

At that time, however, formal methods for calculating ATC or AFC did not exist. 25
Although Order Nos. 888 and 889 obligated each public utility to calculate and post ATC, and to
describe their methodologies for such calculations in their OATT, the Commission did not
mandate the use of specific methodologies. The Commission only required Transmission Service
Providers to base their calculations on “current industry practices, standards and criteria.”26 As a
result, the Commission noted in Order No. 729, “a variety of methodologies to calculate ATC were
used with very few clear rules governing their use and very often little transparency about the
nature of the calculations.”27
In February 2007 the Commission issued Order No. 890 to address and remedy continued
opportunities for undue discrimination under the pro forma OATT adopted in Order No. 888.
Among other things, the Commission sought to standardize the manner in which ATC/AFC was
calculated to address market-related concerns that “the lack of a consistent and transparent
methodology for calculating ATC gives transmission providers the ability and opportunity to
unduly discriminate in the provision of open access transmission service.”28 The Commission
asserted that “[i]mproving transparency and consistency of ATC calculation methodologies will
eliminate transmission service providers’ wide discretion in calculating ATC and ensure that
customers are treated fairly in seeking alternative power supplies.”29 In addition to these marketrelated concerns, the Commission also noted that ATC/AFC calculations raise reliability issues,

25

See Order No. 729 at P 7.

26

Order No. 889, FERC Stats. & Regs. ¶ 31,035 at 31,750.

27

Order No. 729 at P8.

Order No. 890 at P 68. The Commission also noted in Order No. 729 that “[o]n systems where
transmission capacity is constrained, a lack of transparency and consistency in the calculation of available transfer
capability has led to recurring disputes over whether transmission service providers have performed those
calculations in a way that discriminates against competitors.” Order No. 729 at P 90.
28

29

See Order No. 729 at P 2.

10

namely, the need for a transmission provider to know of its neighbors’ system conditions affecting
its own ATC values.30
In Order No. 890, the Commission required industry-wide consistency and transparency of
all components of ATC and AFC calculations and certain definitions, data and modeling
assumptions.31 In Order No. 693, the Commission reiterated its concerns articulated in Order No.
890 and directed NERC and the industry to develop Reliability Standards that provide for
consistency and transparency in the methodologies used by transmission providers to calculate
ATC and the components thereto.32
In response to the requirements of Order No. 890 and related directives of Order No. 693,
NERC submitted for Commission approval the six Existing MOD A Standards. MOD-001-1a
serves as an umbrella standard that contains the generic requirements applicable to determining
ATC and AFC, and requires each applicable entity to select and implement one or more of the
three methodologies found in MOD-028-2 (Area Interchange Methodology), MOD-029-1a (Rates
System Path Methodology) and MOD-030-2 (Flowgate Methodology).33 MOD-004-1 and MOD008-1 provide for the consistent calculation, verification, preservation, and use of CBM and TRM,
respectively, which, as noted above, are inputs into ATC/AFC calculations.

30

Order No. 890 at P 195.

31

Order No. 890 at P 1029.

32

Order No. 693 at PP 1020-22.

33

Reliability Standards MOD-028, MOD-029, and MOD-030 share fundamental equations that, while
mathematically equivalent, are written in slightly different forms. As a result, the manner of determining the
components varies between methodologies. The employment of any two methodologies, given the same inputs, may
produce similar, but not identical, results.

11

In Order No. 729, the Commission approved the six Existing MOD A Standards but
directed NERC to modify certain aspects of those standards.34
2.

History of Project 2012-05 ATC Revisions

In February 2013 NERC initiated an informal process to develop proposed modifications
to the Existing MOD A Standards to address the outstanding Commission directives from Order
No. 729. Participants in this informal process were industry subject matter experts, NERC staff,
and FERC staff from its Office of Electric Regulation. The informal group met numerous times
between February 2013 and July 2013, both in person and by conference call, to discuss the
outstanding FERC directives and, given their experience with the Existing MOD A Standards,
ways to improve those standards. The informal group also conducted industry outreach to obtain
feedback on the existing standards.
In evaluating the Existing MOD A Standards, the participants in the informal process
concluded that a number of the requirements in those Reliability Standards provided little or no
reliability benefit and may only serve a commercial function. The participants concluded, for
instance, that a requirement detailing the specific methodologies that must be used to determine
ATC or AFC was not necessary from a reliability perspective. Rather, the participants maintained,
to address any reliability concerns, NERC’s Reliability Standards need only require that: (1)
entities that determine ATC/AFC and/or TTC/TFC, do so in a manner that accounts for system
limits and relevant system conditions; and (2) entities share the methodologies and data used to
determine ATC/AFC, TTC/TFC, CBM and TRM with other entities that need such information
for their own determinations or to operate and/or plan the Bulk-Power System in a reliable manner.

34

As noted above, the Commission approved Reliability Standard MOD-028-1 in Order No. 729, which was
subsequently replaced by currently effective Reliability Standard MOD-028-2, which was approved in Order No.
782.

12

The informal participants sought to reorient the Existing MOD A Standards to focus
exclusively on Bulk-Power System reliability issues, consistent with the ERO’s expertise and core
mission of developing and enforcing standards that address Bulk-Power System reliability. To
that end, the informal participants developed a proposed standard that consolidated the Existing
MOD A Standards into a single standard that exclusively addressed the reliability-related impact
of ATC and AFC determinations. The intent was to remove those elements of the Existing MOD
A Standards that were unnecessary from a reliability perspective, while retaining and improving
upon those elements that address Bulk-Power System reliability concerns.

In drafting the

consolidated standard, the informal participants also sought to respond to Commission’s directives
from Order No. 729.
Project 2012-05 ATC Revisions (MOD A) was formally initiated on July 11, 2013 with
the posting of a Standard Authorization Request along with the draft standard for a 45-day formal
comment period and ballot. Following this posting, a standard drafting team of industry experts
was formed, many of whom were participants in the informal process. On October 4, 2013, after
addressing industry comment on the initial draft, a second draft of the proposed standard was
posted for an additional 45-day comment period and ballot, which received a quorum of 81.69%
and an approval of 82.97%. Following approval of the proposed standard in a Final Ballot, the
NERC Board of Trustees approved proposed MOD-001-2 and the retirement of the Existing MOD
A Standards on February 6, 2014.
IV.

JUSTIFICATION FOR APPROVAL
As discussed in Exhibit C, proposed Reliability Standard MOD-001-2 satisfies the

Commission’s criteria in Order No. 672 and is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. This section provides: (i) a discussion of the reliability
13

issues associated with ATC and AFC determinations; (ii) an explanation of how the proposed
Reliability Standard comprehensively addresses those reliability issues; (iii) a discussion of
outstanding Commission directives; and (iv) a discussion of the enforceability of the proposed
Reliability Standard.
A.

Reliability Issues Associated with ATC and AFC Determinations

As noted, ATC and AFC are commercially-based values used to facilitate a market for
unused transmission capacity in an open access environment. Across North America there are a
variety of methods used to determine ATC/AFC values based on the Transmission Service
Provider’s specific transmission system, market conditions, and available data, although all of the
methods fall under one of the three broad methodologies set forth in MOD-028, MOD-029, and
MOD-030. In general, ATC/AFC values represent a Transmission Service Provider’s reasonable
estimate of the transmission capacity available for sale at a particular point in time based on the
following forecasted inputs: TTC/TFC, ETC, CBM, TRM, postbacks and counterflows.
ATC/AFC determinations thus reflect a Transmission Service Provider’s prediction of
future system conditions. For instance, when a Transmission Service Provider posts ATC/AFC
values for a daily transfer 30 days in advance of the operating day for which ATC/AFC is being
determined, those values are a prediction of the amount of transfer capability that will be available
during that operating day based on expected system uses, load forecasts, expected outages and
other system conditions. As that operating day approaches Real-time, these conditions may vary
from unconstrained market conditions, to constrained, to oversold, and back to unconstrained as
forecast data changes.
ATC/AFC values also reflect the Transmission Service Provider’s tolerance for curtailment
or redispatch risk. Depending on the type of transmission service being sold (firm or non-firm),
Transmission Service Providers may reserve (or set aside) capacity – either through a TRM value
14

or the manner in which they determine ETC, or both – to provide themselves a greater margin for
responding to changing system conditions and/or Real-time events without having to curtail
service. The level of risk tolerance is unique to each Transmission Service Provider based on its
expectations of the amount of committed capacity that will be used at a given point in time. 35 In
some regions, Transmission Service Providers determine ATC/AFC in a manner that seeks to
ensure that, following a single event, no transmission service has to be curtailed. In other regions,
it is expected that following a single event, some transmission service may have to be curtailed.
Regardless of the differences in methodology or the level of a Transmission Service
Provider’s risk tolerance, ATC/AFC values do not directly control the operation of the Bulk-Power
System. Transmission Operators are ultimately responsible for operating the grid in a reliable
manner consistent with System Operating Limits, not ATC/AFC values.36 NERC’s Reliability
Standards prohibit the scheduling and delivery of transmission service if such action would cause
a violation of System Operating Limits or otherwise adversely affect reliability, regardless of the
amount of ATC or AFC that is posted and sold by the Transmission Service Provider. It is the
Transmission Operator’s responsibility, when operating its system in Real-time, to monitor
changing system conditions and respond to any events, such as a facility exceeding its System
Operating Limit.

35

The amount of committed capacity will not necessarily match the amount of capacity transmission
customers will actually use in Real-time. This is increasingly the case because of the proliferation of variable
resources and renewable portfolio standards that encourage transmission customers to purchase transmission rights
in excess of their needs so as to maintain flexibility to use energy from a number of different resources.
36

The Transmission Operations (TOP) and Interconnection Reliability Operations and Coordination (IRO)
group of Reliability Standards mandate that Transmission Operators and Reliability Coordinators operate to System
Operating Limits and Interconnection Reliability Operating Limits, not ATC or AFC values. It is important to
recognize that some Transmission Operators equate TTC/TFC and System Operating Limits such that the TTC/TFC
value and subsequent ATC/AFC value has direct relevance to the reliability of the grid. In these areas, exceeding
the TTC/TFC value would be a violation of a System Operating Limit. For other Transmission Operators, due to the
configuration of their systems, TTC/TFC values do not necessarily equate to System Operating Limits. For these
systems, while ATC/AFC values remain an accurate predictor of transfer capability, they are not necessarily good
predictors of system reliability limits.

15

Nevertheless, ATC/AFC values have the potential to influence Real-time conditions on the
Bulk-Power System and impact Real-time operations, and, in turn, it is important for these values
to be determined in a manner that supports the reliable operation of the Bulk-Power System.
Specifically, the amount of ATC/AFC that is actually purchased and scheduled has an effect on
the system conditions that Transmission Operators monitor in Real-time. As more ATC/AFC is
posted, sold and scheduled, the transmission system is closer to reaching its reliability operating
limits. If, for instance, there is 200 MW of ATC/AFC but only 100 MW is sold and delivered in
Real-time, then the transmission system is operating below its predicted limit. If all 200 MW were
sold and delivered, the system is operating at the predicted limit. If, however, ATC/AFC is
overestimated such that the predicted transfer capability is not consistent with or exceeds the Realtime reliability limits, it could lead to oversold conditions that place significant burdens on the
Transmission Operator. That is, oversold conditions could result in the overscheduling of a
constraint, Real-time system loadings approaching System Operating Limits or violations of
System Operating Limits, which trigger the need for the Transmission Operator to take corrective
action to maintain system reliability, whether by curtailing transmission service, redispatching
generation or other means.
Accordingly, there is a need for NERC”s Reliability Standards to help ensure that
ATC/AFC values are determined in a manner that supports, or is consistent with, the reliable
operation of the Bulk-Power System (i.e., in a manner that seeks to reduce the possibility of
oversold conditions and the potential for violations of System Operating Limits). The first step in
achieving this objective is to require that entities that determine TTC/TFC and/or ATC/AFC values
do so in a manner that accounts for relevant reliability limits and expected system conditions. The
more closely these values align with system limits and conditions in Real-time, the lesser the

16

likelihood that oversold conditions will occur. Although ATC/AFC predictions are unlikely to
exactly match system conditions in Real-time, requiring entities to account for system limits and
expected system conditions should increase the accuracy of ATC/AFC predictions and ease the
burden on Transmission Operators in Real-time.
Additionally, there is a need for NERC’s Reliability Standards to require Transmission
Service Providers and Transmission Operators that determine ATC/AFC, TTC/TFC, ETC, CBM
and TRM to do so in a transparent manner and to share information and data underlying those
determinations with those who need such data for their own determinations or other reliability
purposes. As the Commission recognized in Order No. 890, it is important that Transmission
Service Providers know of its neighbors’ system conditions affecting its own ATC/AFC values.37
The standard drafting team agreed that increasing transparency and coordination can help reduce
the number of instances where ATC/AFC is overestimated. Accordingly, it is important for
planners and operators of the Bulk-Power System to understand the manner in which ATC/AFC
is determined by their neighbors and maintain awareness of available transmission system
capability and future flows on their own systems as well as pertinent neighboring systems.
B.

Proposed MOD-001-2 Comprehensively Addresses the Reliability Issues
Associated with ATC and AFC Determinations

The purpose of the proposed Reliability Standard is to replace, consolidate and improve
upon the Existing MOD A Standards in establishing an efficient framework that comprehensively
addresses the reliability concerns identified above. The proposed Reliability Standard helps ensure
that: (1) ATC/AFC and TTC/TFC determinations account for system limits and relevant system
conditions; (2) ATC/AFC, TTC/TFC, CBM and TRM methodologies are documented and

37

Order No. 890 at P 195.

17

available to any registered entity with a demonstrated reliability need for such information; (3) the
data supporting those determinations are available to those entities who need such data to conduct
their own determinations; and (4) any entity with a reliability need has a mechanism for requesting
that the Transmission Service Provider or the Transmission Operator respond to requests for
clarifications regarding their ATC/AFC, TTC/TFC, CBM or TRM methodologies, as applicable.
The proposed Reliability Standard contains six requirements. Requirements R1, R2, R3
and R4 require documentation of the methodologies for determining TTC/TFC, ATC/AFC, CBM
and TRM, respectively.

Requirements R5 and R6 cover information and data sharing

requirements. The following is a description of each requirement of proposed MOD-001-2.
Requirement R1 requires each Transmission Operator that determines TTC or TFC to
“develop a written methodology (or methodologies) for determining TFC or TTC values.” As
noted, TTC and TFC represent the total amount of power that may be transferred from one area to
another area of the system by way of all paths between those areas (TTC) or the maximum flow
capability on a particular Flowgate (TFC) under specific conditions.38 As such, TTC and TFC
values are the starting points for determining ATC and AFC values. The requirement to document
the TTC/TFC methodology, together with the information sharing requirements in Requirements
R5 and R6, discussed below, will provide Transmission Service Providers and other Transmission
Operators (and, to the extent necessary, other functional entities that need such information for
reliability purposes), the ability to clearly understand how TTC/TFC values are determined. To
ensure that Transmission Operators follow their written methodology and that the written

In NERC’s Glossary, TTC is defined as “[t]he amount of electric power that can be moved or transferred
reliably from one area to another area of the interconnected transmission systems by way of all transmission lines
(or paths) between those areas under specified system conditions.” TFC is defined as “[t]he maximum flow
capability on a Flowgate, [] not to exceed its thermal rating, or in the case of a Flowgate used to represent a specific
operating constraint (such as a voltage or stability limit), [] not to exceed the associated System Operating Limit.”
38

18

methodology is updated whenever necessary, Requirement R1 provides that the written
methodology must “reflect the Transmission Operator’s current practices for determining TFC or
TTC values.”
As discussed above, to help ensure that ATC/AFC determinations support the reliable
operation of the Bulk-Power System, TTC/TFC values need to have a sound basis in, and be
derived from, system limits.

To that end, Requirement R1, part 1.1 provides that each

Transmission Operator’s TTC/TFC methodology must describe the method used to account for
the following limitations in both the pre- and post-contingency state: facility ratings, system
voltage limits, transient stability limits, voltage stability limits, and other System Operating Limits.
Additionally, as noted above, to provide for reliable ATC/AFC determinations, TFC and
TTC values need to account for any reliability constraints that limit those values and other system
conditions forecasted for the time period for which those values are determined. Accordingly,
pursuant to Requirement R1, part 1.2, a Transmission Operator’s TTC/TFC methodology must
describe the method used to account for each of the following elements, provided such elements
impact the determination of TFC or TTC: (1) the simulation of transfers performed through the
adjustment of generation, Load, or both; (2) transmission topology, including, but not limited to,
additions and retirements; (3) expected transmission uses; (4) planned outages; (5) parallel path
(loop flow) adjustments; (6) Load forecast; and (7) generator dispatch, including, but not limited
to, additions and retirements.
Lastly, to help ensure that TTC/TFC determinations account for reliability constraints on
neighboring systems, Requirement R1, part 1.3 requires that a Transmission Operator’s TTC/TFC
methodology “describe the process for including any reliability-related constraints that are
requested to be included by another Transmission Operator.” This will provide other Transmission

19

Operators the opportunity to ensure that constraints on their systems are properly considered by
neighboring entities. Part 1.3 also sets the threshold for when a requested constraint need be
included. For users of the Flowgate Method, part 1.3.1 states that an impact test must be used and,
if a generator to Load transfer in a registered entity’s area or a transfer to a neighboring registered
entity impacts the requested constraint by five percent or greater, the requested constraint shall be
included in the TFC determination. Part 1.3.2 states that users of the Area Interchange or Rated
System Path Methodology must account for requested constraints that have a five percent or
greater distribution factor for a transfer between areas in the TTC determination. Under part 1.3.3,
a different method for determining whether requested constraints need to be included in the TFC
or TTC determination may be used if agreed to by the Transmission Operators.
Assigning the responsibility for determining TTC/TFC values to Transmission Operators
is consistent with the NERC Functional Model39 and the Existing MOD A Standards. It also aligns
with a Transmission Operator’s responsibility of determining System Operating Limits. The
Transmission Operations (TOP) and Facilities Design, Connections and Maintenance (FAC) group
of Reliability Standards require that Transmission Operators establish System Operating Limits
that help ensure acceptable performance criteria both pre- and post-contingency. In doing so,
Transmission Operators perform power flow analyses that reflect the expected system conditions
of the Bulk-Power System. To determine TTC/TFC values, a transfer analysis needs to be
performed to help ensure that the TTC/TFC values are established in a manner that accounts for
System Operating Limits for any specified system conditions. These transfer analyses will
simulate power system transfers and establish a TTC/TFC that does not cause Facility Ratings,

The NERC Functional Model (at 39) states that the Transmission Operator “[p]rovides Total Transfer
Capabilities and System Operating Limits to, and coordinates Available Transfer Capability with, Transmission
Service Provider.”
39

20

voltage limits, transient stability limits, and voltage stability limits to be exceeded in the pre- and
post-contingency state. As such, while TTC/TFC values may not necessarily equate to System
Operating Limits for all systems and in all instances,40 TTC/TFC values are most appropriately
determined by the functional entity that is responsible for ensuring that Facility Ratings, voltage
limits, transient stability limits, and voltage stability limits are not violated in the pre- and postcontingency state.
The standard drafting team acknowledged, however, that certain Transmission Operators
may not determine TTC or TFC values because, among other things, another Transmission
Operator makes the determination for their system (e.g., Regional Transmission Organizations and
Independent System Operators may determine TTC/TFC for Transmission Operators in their
footprint) or because it does not have a path or Flowgate for which ATC or AFC is determined. It
is unnecessary for such Transmission Operators to be subject to a requirement to determine
TTC/TFC. Requirement R1 is thus specifically limited to Transmission Operators that determine
TTC or TFC and establishes the requirements that such Transmission Operators must satisfy in
determining TTC/TFC. It does not mandate which Transmission Operators must determine
TTC/TFC.
Requirement R2 requires each Transmission Service Provider that determines ATC or AFC
to “develop an Available Transfer Capability Implementation Document (ATCID) that describes
the methodology (or methodologies) it uses to determine AFC or ATC values.” The ATCID must
“reflect the Transmission Service Provider’s current practices for determining AFC or ATC

40

In some instances, TTC/TFC values will be the same as the System Operating Limit. For instance,
transient and voltage stability limits are calculated and expressed as pre-contingent path or interface flow values.
Accordingly, transfer analyses are required to establish the transient and voltage stability limits. It is possible that
transient stability limits and voltage stability limits may define TTC/TFC for certain paths, rendering TTC/TFC and
the path’s SOL to be the same value.

21

values.” The requirement to have an ATCID works in concert with the information sharing
requirements of Requirements R5 and R6 to provide the necessary transparency and coordination.
Because it is important for ATC/AFC values to account for system conditions at the time
for which those values are determined, Requirement R2, part 2.1 provides that the ATCID must
describe the method used to account for each of the following elements, provided such elements
impact the determination of ATC/AFC: (1) the simulation of transfers performed through the
adjustment of generation, Load, or both; (2) transmission topology, including, but not limited to,
additions and retirements; (3) expected transmission uses; (4) planned outages; (5) parallel path
(loop flow) adjustments; (6) Load forecast; and (7) generator dispatch, including, but not limited
to, additions and retirements. This provision is not duplicative of Requirement R1, part 1.2
because some methods for determining ATC/AFC account for these elements in the determination
of TTC/TFC while others do not. Part 2.1 of Requirement R2 is thus necessary to ensure that
where those elements are not accounted for in the determination of TTC/TFC, the Transmission
Service Provider does so in its ultimate determination of ATC/AFC.41
Lastly, part 2.2 of Requirement R2 provides that Transmission Service Providers that use
the Flowgate Methodology shall, for reliability-related constraints identified in Requirement R1,
part 1.3, use the AFC determined by the Transmission Service Provider for that constraint. This
will help ensure that each Transmission Service Provider uses consistent values for those
constraints.
Requirement R3 requires Transmission Service Providers to “develop a Capacity Benefit
Margin Implementation Document (CBMID) that describes its method for determining CBM

41

Where the Transmission Operator accounts for these elements in its TTC/TFC determination, the
Transmission Service Provider’s ATCID need only explain that the Transmission Operator accounts for such
elements when determining TTC/TFC.

22

values.” The CBMID must “reflect the Transmission Service Provider’s current practices for
determining CBM values.” As noted above, CBM is a component of ATC/AFC and, as defined
in the NERC Glossary, is the “amount of firm transmission transfer capability preserved by the
[Transmission Service Provider] for Load Serving Entities (LSEs), whose loads are located on that
Transmission Service Provider’s system, to enable access by the LSEs to generation from
interconnected systems to meet generation reliability requirements.” Preservation of CBM allows
an LSE to reduce its installed generating capacity below that which may otherwise have been
necessary without interconnections to meet its generation reliability requirements. The
transmission transfer capability preserved as CBM is intended to be used by the LSE only in times
of emergency generation deficiencies. A clear explanation of how the CBM value is determined
is an important aspect of a Transmission Service Provider’s ability to communicate its method for
determining ATC/AFC values to Transmission Operators and other entities.

Because

Transmission Service Providers have other obligations that reference CBM, the standard drafting
team decided to require Transmission Service Providers to keep a CBMID in a separate
requirement.
Requirement R4 requires each Transmission Service Provider to “develop a Transmission
Reliability Margin Implementation Document (TRMID) that describes its method for determining
TRM values.” The TRMID must “reflect the Transmission Operator’s current practices for
determining TRM values.” As noted above, TRM is a component of ATC/AFC and, as defined in
the NERC Glossary, is the “[t]he amount of transmission transfer capability necessary to provide
reasonable assurance that the interconnected transmission network will be secure.” TRM accounts
for the inherent uncertainty in system conditions and the need for operating flexibility to ensure
reliable system operation as system conditions change. A clear explanation of how the TRM value

23

is determined is an important aspect of a Transmission Service Provider’s ability to communicate
its method for determining ATC/AFC values to Transmission Operators and others. Because
Transmission Service Providers have other obligations that reference TRM, the standard drafting
team decided to keep a TRMID in a separate requirement.
Requirement R5 requires each Transmission Operator and Transmission Service Provider,
within 45 days of a written request from a Planning Coordinator, Reliability Coordinator,
Transmission Operator, Transmission Planner, Transmission Service Provider, or any other
registered entity with a reliability need, to provide the requesting entity: (1) a written response to
any request for clarification of its TTC/TFC methodology, ATCID, CBMID or TRMID, as
applicable; and (2) its TTC/TFC methodology, ATCID, CBMID and TRMID, as applicable, if not
already publicly posted. Requirement R5 addresses the reliability need for other entities to
understand the methodologies used by Transmission Service Providers for determining ATC/AFC
and CBM, and the methodologies used by Transmission Operator for determining TTC/TFC and
TRM. Clearly communicating the methods for determining ATC/AFC, TTC/TFC, CBM, and
TRM is necessary for the reliable operation of the Bulk-Power System. As noted above, a lack of
coordination and transparency could result in cases where ATC or AFC is overestimated. The
requirement to provide a written response to a request for clarification provides entities a formal
mechanism for the necessary coordination.
Requirement R6 provides a data sharing mechanism that allows each Transmission
Operator and Transmission Service Provider to access the best available data (e.g., load forecasts,
expected dispatch, planned outages) for use in its determination of AFC/ATC, TTC/TFC, CBM
and TRM values, as applicable. The sharing of data is designed to help increase the accuracy of
ATC/AFC, TTC/TFC, CBM and TRM determinations and, in turn, decrease the potential for

24

oversold conditions. Requirement R6 covers both requests for data on an ongoing basis (e.g., a
request for load data on a weekly or monthly basis) and requests for data that is limited to a single
occasion or on a non-recurring basis. Specifically, Requirement R6 provides as follows:
R6.

Each Transmission Operator or Transmission Service Provider that receives a written
request from another Transmission Operator or Transmission Service Provider for data
related to AFC, ATC, TFC, or TTC determinations that (1) references this specific
requirement, and (2) specifies that the requested data is for use in the requesting party’s
AFC, ATC, TFC, or TTC determination shall take one of the actions below.
6.1

In responding to a written request for data on an ongoing basis, the Transmission
Service Provider or Transmission Operator shall make available its data on an
ongoing basis no later than 45 calendar days from receipt of the written request.
Unless otherwise agreed upon, the Transmission Operator or Transmission Service
Provider is not required to alter the format in which it maintains or uses the data or
make available the requested data on a more frequent basis than it produces the data
and in no event shall it be required to provide the data more frequently than once
an hour.

6.2

In responding to all other data requests, each Transmission Operator or
Transmission Service Provider shall make available the requested data within 45
calendar days of receipt of the written request. Unless otherwise agreed upon, the
Transmission Operator or Transmission Service Provider is not required to alter the
format in which it maintains or uses the data

To ensure that Requirement R6 does not conflict with an entity’s confidentiality, regulatory
or security obligations, part 6.3 of Requirement R6 provides:
If making available any requested data under parts 6.1 or 6.2 of this requirement is
contrary to the Transmission Operator’s or Transmission Service Provider’s
confidentiality, regulatory, or security requirements, the Transmission Operator or
Transmission Service Provider shall not be required to make available that data;
provided that, within 45 calendar days of the written request, it responds to the
requesting registered entity specifying the data that is not being provided, on what
basis and whether there are any options for resolving any of the confidentiality,
regulatory or security concerns.
The proposed Reliability Standard includes all of the requirements necessary to facilitate a
market for available transmission capacity that protects Bulk-Power System reliability. As noted
above, the standard drafting team concluded that a number of requirements from the Existing MOD
A Standards were not necessary to protect Bulk-Power System reliability and need not be included
25

in the proposed Reliability Standard. The standard drafting team found that the only requirements
necessary for reliability are those that: (1) require entities to account for system limits and relevant
system conditions when determining TTC/TFC and ATC/AFC; and (2) establish a framework
whereby such determinations are made in a transparent fashion so that planners and operators of
the Bulk-Power System maintain awareness of available transmission system capability and future
flows on their own systems as well as those of their neighbors.
Accordingly, in contrast to the Existing MOD A Standards, proposed MOD-001-2 does
not prescribe the specific methods an entity must use to determine ATC/AFC and its components.42
The standard drafting team concluded that such detail is not necessary for reliability purposes. So
long as an entity accounts for system limits and relevant system conditions, and shares its
methodology and data with entities that need such information for reliability purposes, failure to
follow one of the predetermined methods in the Existing MOD A Standards would not lead to
oversold condition or otherwise adversely affect reliability. Additionally, proposed MOD-001-2
does not include requirements that address commercial or business practice issues rather than
reliability needs. For example, proposed MOD-001-2 does not include the requirement from the
Existing MOD A Standards that prohibits Transmission Service Providers from making
transmission capability available on a more conservative basis for commercial purposes than for
either planning for native load or use in actual operations. This requirement addresses the marketbased concern regarding the potential for differing treatment of native load customers and
transmission service customers.43 Exhibit D hereto is a mapping document that shows which of

42

This is consistent with the approach for the calculation of System Operating Limits, Interconnection
Reliability Operating Limits, and facility ratings. See FAC-008-3 – Facility Ratings; FAC-101-2.1 – System
Operating Limits Methodology for the Planning Horizon; FAC-011-2 – System Operating Limits Methodology for
the Operations Horizon. NERC’s Reliability Standards do not mandate the methods an entity must use to calculate
these values.
43

See Order No. 729 at P 15.

26

the requirements from the Existing MOD A Standards have been carried over to the proposed
Reliability Standard and which are not included, along with the standard drafting team’s reasoning.
The consolidation of the reliability-based requirements of the Existing MOD A Standards
into a single standard focused exclusively on requirements necessary to protect reliability is
consistent with the ERO’s jurisdiction over reliability matters and NERC’s primary mission to
develop standards that support the reliable operation of the Bulk-Power System. It is also
consistent with Commission orders supporting (1) the removal of requirements from NERC’s
Reliability Standards that provide little protection for Bulk-Power System reliability, and (2) the
modification of standards to increase the efficiency of the ERO compliance program.”44
NERC and the standard drafting team recognize, however, that certain of the requirements
from the Existing MOD A Standards that are not included in the proposed Reliability Standard
may be necessary for market or commercial purposes. Accordingly, on February 7, 2014, NERC
formally requested that NAESB, which administers business practice standards for the electric
industry, consider whether any of those requirements are appropriate for incorporation into
NAESB’s WEQ Standards to help ensure a non-discriminatory market for transmission service.
Prior to its formal request, NERC and the standard drafting team worked with NAESB to explain
the approach in the proposed Reliability Standard and discuss the requirements that are were not
being retained.

NERC understands that NAESB, working through its business practice

development process, is considering whether to incorporate into its WEQ Standards those elements
from the Existing MOD A Standards, if any, that relate to commercial or business practices. The

44

See Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC
¶ 61,147 (2013); North American Electric Reliability Corp., 138 FERC ¶ 61,193, at P 81, order on reh’g and
clarification, 139 FERC ¶ 61,168 (2012).

27

proposed implementation plan for MOD-001-2, as discussed below, is intended to accommodate
NAESB’s business practice development process.
C.

Proposed MOD-001-2 Satisfies Outstanding Commission Directives

In Order No. 729, the Commission directed the ERO to develop certain modifications to
the Existing MOD A Standards. As discussed below, the standard drafting team addressed those
directives to the extent that they relate to the reliability requirements retained in proposed MOD002-1. For those directives that relate to requirements that were not retained in the proposed
Reliability Standard, NAESB may consider whether those directives are appropriately addressed
in its WEQ Standards. The following is a discussion of each of the outstanding directives from
Order No. 729, which are also described in Exhibit E hereto.
Date Retention: The Commission’s directed NERC to increase the document retention
requirements of the Existing MOD A Standards to a term of five years to be consistent with the
enforcement provisions in Order No. 670.45 Consistent with FERC’s directive, proposed MOD001-2 requires applicable registered entities to retain the implementation/methodology documents
required under Requirements R1-R4 for five years. The proposed standard provides a graduated
time frame for the retention of data related to the calculation of hourly, daily, and monthly values.
Evidence of hourly values must be retained for 14 days, daily values for 30 days and monthly
values for 60 days. The standard drafting team concluded there was little to no reliability benefit
of requiring entities to retain such detailed supporting data of the calculations for longer periods.
To comply with Commission requirements under Order No. 670, however, entities may be
required to retain such supporting data for longer periods.

45

Order No. 729 at P 129.

28

Disclosure of Methodology Documents: The Commission directed NERC to modify MOD001-1 to require disclosure of implementation documents to any registered entity who
demonstrates a reliability need for such information. 46 Consistent with the Commission’s
directive, Requirement R5 of the proposed Reliability Standard requires that the implementation
documents be made available to any registered entity that demonstrates a reliability need for such
information.
Consideration of Generator and Transmission Line Ratings: The Commission directed
NERC to consider the treatment of generator nameplate ratings and transmission line ratings in the
calculation of ATC/AFC.47 The Commission has since withdrawn this directive and it is not
addressed in the proposed standard. 48 NERC notes that because the treatment of generator
nameplate and transmission line ratings relate to the determination of TTC/TFC and ETC, a
Transmission Operator’s and Transmission Service Provider’s treatment of facility ratings will be
disclosed in its written methodology for TTC/TFC or its ATCID, respectively, in accordance with
Requirements R1 and R2 of the proposed standard. Further, to the extent that this issue relates to
a commercial or business practice, NAESB may consider whether it is appropriate to address this
directive in its WEQ Standards.
Benchmarking and Updating Requirements: The Commission directed NERC to develop
benchmarking and updating requirements to measure modeled available transfer and Flowgate
capabilities against actual values.49 The Commission stated that “[u]pdating and benchmarking of
models to actual events will ensure greater accuracy, which will benefit information provided to
46

Order No. 729 at P 151.

47

Order No. 729 at P 160.

48

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶
61,147 at PP 25-26, Attachment A (2013).
49

Order No. 729 at P 162.

29

and used by adjacent transmission service providers who rely upon such information to plan their
systems”50 The standard drafting team concluded that, by improving transparency, the proposed
Reliability Standard is responsive to the Commission’s concern of increasing accuracy of
ATC/AFC predictions. Requirements R1 (part 1.2) and R2 (part 2.1) of the proposed standard
require that a Transmission Operator’s and a Transmission Service Provider’s methods for
determining TTC/TFC and AFC/ATC, respectively, account for system topology, including
additions and retirements as well as expected system usage, planned outages, Load forecast and
expected generation dispatch. By describing how the methodology accounts for these elements,
adjacent systems will be able to effectively model their own transfer or Flowgate capabilities. The
standard drafting team found that because each part of the country has a different sensitivity to
these elements and the frequency with which they change, there was no additional reliability
benefit in mandating the frequency with which an entity must benchmark or update its models.
Additionally, under Requirement R5, a Transmission Service Provider or a Transmission Operator
may be requested to clarify its benchmarking and updating practices, if not already set forth in its
documented methodology. Finally, pursuant to Requirement R6 of the proposed standard, entities
are required to share their data with others, which also increases the accuracy of ATC/AFC
predictions by proving entities access to the most up to date information available.
Specifying Base Generation Schedules: The Commission directed that NERC develop
modifications to MOD-028-1 and MOD-029-1 related to the treatment of base generation
schedules used in the calculation of ATC. 51 The standard drafting team determined that this

50

Id.

51

Order No. 729 at P 173. Specifically, FERC directed NERC to modify MOD-028-1 and MOD-029-1 to
specify that base generation schedules used in the calculation of available transfer capability will reflect the
modeling of all designated network resources and other resources that are committed to or have the legal obligation
to run, as they are expected to run, and to address the effect on available transfer capability of designating and
undesignating a network resource.

30

directive does not relate to the reliability issues associated with ATC or AFC determinations and,
in turn, it did not explicitly address this directive in the proposed standard. Specifically, the
standard drafting team concluded that there is no reliability purpose served by mandating how
generation and network resources should be treated so long as it is transparent. Under Requirement
R2 of the proposed standard, a Transmission Service Provider is expected to describe its practices
related to the treatment of base generation schedules and the effect of designating and
undesignating a network resource.

Additionally, under Requirement R5 of the proposed

Reliability Standard, the Transmission Service Provider is required to respond to requests for
clarification of its practices on this issue. To the extent necessary from a market perspective,
NAESB may consider whether to address this issue in its WEQ Standards.
Updates for Constrained Facilities: The Commission directed NERC to consider
comments regarding the need to require more frequent updates on constrained facilities. 52 The
Commission has since withdrawn this directive and it is not addressed in the proposed standard.53
NERC notes, however, that an entity’s ATCID could address this issue. To the extent this issue is
relevant from a commercial perspective, NAESB may also consider whether to address this issue
in its WEQ standards.
Updates due to Changes in System Conditions: The Commission directed modifications to
MOD-001-1 and MOD-030-2 to clarify that material changes in system conditions will trigger an
update to ATC/AFC values whenever practical.54 The standard drafting team determined that it
was not necessary to explicitly address this directive in the proposed standard. That is because the

52

Order No. 729 at P 179.

53

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶
61,147 at PP 25-26, Attachment A (2013).
54

Order No. 729 at P 179.

31

methodology described in the ATCID should include the entity’s updating practices. An explicit
requirement to update values whenever practical is unnecessary. Further, updating ATC/AFC
values as soon as practical primarily serves a commercial need to provide updated information to
the market.

From a reliability perspective, it is ultimately the Transmission Operator’s

responsibility to operate the system in a reliable manner and consistent with SOLs, which update
as system conditions change. To the extent necessary from a commercial perspective, NAESB
may consider whether to address this issue in its WEQ Standards.
Double Counting: The Commission directed modifications to MOD-001-1 to prevent
double counting of data inputs and assumptions.55 The standard drafting team concluded that the
proposed Reliability Standard is responsive to the Commission’s concern. By requiring the
documentation and disclosure of the methodologies for determining TTC/TFC, AFC/ATC, CBM
and TRM, entities will understand how Transmission Operators and Transmission Service
Providers determine these values and, in turn, understand where there is potential for double
counting. If the potential for double counting is identified, entities can take the necessary steps to
reduce the risks associated with double-counting, including using Requirement R5 to request that
the applicable Transmission Operator or Transmission Service Provider provide clarification. To
the extent it deems necessary, NAESB may consider whether the potential for double-counting
needs to be addressed in greater detail in its business practice standards to address any marketrelated concerns.
Inconsistent Modeling Practices: The Commission directed modifications to MOD-001-1
to require that entities “include in their implementation documents any inconsistent modeling

55

Order No. 729 at P 184.

32

practices along with a justification for such inconsistencies.” 56 The proposed standard is
responsive to the Commission’s concern. Requirement R1, part 1.2 and Requirement R2, part 2.1
require that Transmission Operators and Transmission Service Providers document their modeling
practices for determining TTC/TFC and AFC/ATC, respectively.57 Entities will thus be required
to disclose any inconsistent modeling practices (e.g., whether they use different modeling practices
for different time frames).

Additionally, Requirement R5 allows entities to request that

Transmission Service Providers and Transmission Operators clarify their methodologies, which
may include requests related to the Transmission Service Providers’ and Transmission Operators’
modeling practices. Should NAESB see a need for additional detail on modeling practices for
purposes of ensuring a non-discriminatory market, it may further consider this directive.
Clarification of Requirements R6 and R7 of MOD-001-1: The Commission directed the
ERO to consider comments regarding (i) clarifying the terms “assumptions” and “no more
limiting” as used in Requirements R6 and R7 of MOD-001-1, and (ii) the use of data and
assumptions for ATC/AFC and TTC/TFC determinations that are consistent with those used in the
planning of operations and system expansion. 58 The Commission has since withdrawn this
directive and it is not addressed in the proposed standard.59 To the extent these issues relate to
business practices, NAESB may consider this issue in its standards development process.
Determination of Generation Capability Import for CBM: The Commission directed
modification to MOD-004-1 to require Load Serving Entities and Resource Planners to determine

56

Order No. 729 at P 192.

For example, entities must describe how they account for “[t]ransmission topology, including, but not
limited to, additions and retirements.”
57

58

Order No. 729 at P 200.

59

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶
61,147 at PP 25-26, Attachment A (2013).

33

generation capability import requirements by reference to one or more relevant studies and
applicable reserve margin or resource adequacy requirements. 60 The standard drafting team
determined that it was not necessary to specifically address this directive in the proposed standard.
The purpose of the proposed Reliability Standard is to help ensure that the determination of
ATC/AFC is accomplished in a manner that supports the reliable operation of the Bulk-Power
System. Because CBM is an input into ATC/AFC values, it is important to understand how a
Transmission Service Provider determines CBM; however, there is no additional reliability benefit
to the transmission system in prescribing the manner in which it determines CBM or the manner
in which Load Serving Entities or Resource Planners determine the appropriate generation
capacity import requirement as part of the sum of CBM to be requested. From a reliability
perspective, it is only important to understand the manner in which such determinations are made.
To the extent this is relevant from a commercial perspective, NAESB may consider this directive
in its standards development process.
Clarification of Term “manage”: The Commission directed NERC to modify MOD-0041 to clarify the term “manage” in Requirement R1.3 to clarify how the transmission service
provider will manage situations where the requested use of CBM exceeds the CBM available. As
noted above, under the proposed Reliability Standard, the Transmission Service Provider must
describe its method for determining CBM in its CBMID. As part of describing its method in the
CBMID, a TSP is expected to describe the manner in which it will manage situations where the
requested use of CBM exceeds the CBM available. As such, the standard drafting team determined
that it is unnecessary to include a specific requirement obligating the TSP to clarify how it will
manage such situations. Additionally, the standard drafting team notes that should a Load Serving

60

Order No. 729 at P 220.

34

Entity not receive all of the CBM it requests, it has the opportunity to make other arrangements to
obtain any necessary capacity. To the extent this issue is relevant to commercial practices, NAESB
may consider this issue further.
Clarification of Phrase “adjacent and beyond Reliability Coordination areas”: The
Commission understood sub-requirement R2.2 of MOD-028-1 to mean that, when determining
TTC, a Transmission Operator shall use a transmission model that includes relevant data from
reliability coordination areas that are not adjacent. The Commission directed NERC to modify
sub-requirement R2.2 to clarify the phrase “adjacent and beyond Reliability Coordination areas.”
The Commission has since withdrawn this directive and it is not addressed in the proposed
standard.61 Additionally, proposed MOD-001-2 does not use the phrase “adjacent and beyond
Reliability Coordination areas.”
Graduated Timeframe for Posting TTC: The Commission directed NERC to consider
modifications to MOD-028-01 related to including a graduated timeframe for posting TTC.62 The
Commission has since withdrawn this directive and it is not addressed in the proposed standard.63
To the extent this issue relates to commercial practices, NAESB may consider this issue in its
standards process.
Distribution Factors used in Calculating TTC: The Commission directed NERC to modify
MOD-028-1 to state that the distribution factors used in calculating TTC must be clearly stated in
the implementation document and applied consistently.64 The standard drafting team concluded

61

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶
61,147 at PP 25-26, Attachment A (2013).
62

Order No. 729 at P 234.

63

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶
61,147 at PP 25-26, Attachment A (2013).
64

Order No. 729 at P 237.

35

that the proposed Reliability Standard is responsive to the Commission’s concern. First, the
proposed reliability standard requires disclosure of the Transmission Operator’s method(s) for
determining TTC/TFC and the Transmission Service Provider’s method(s) for determining
ATC/AFC. These methods will describe the manner in which such entities use distribution factors.
The description must reflect current practices. Further, to the extent an entity seeks clarity on how
distribution factors are used, it may request such clarification under Requirement R5.
Additionally, Requirement R1, part 1.3 of the proposed Reliability Standard requires that
Transmission Operators include, upon request, transmission constraints on neighboring systems
that could impact their TTC/TFC determination. Users of the Area Interchange or Rated System
Path Methodology must describe the process they use in their TTC determinations to account for
requested constraints that have a five percent or greater distribution factor for a transfer between
areas, unless a different method is agreed upon.
Calculating Non-Firm ATC Using Counterschedules: The Commission directed NERC to
consider a commenters’ concern regarding calculating non-firm ATC using counterschedules as
opposed to counterflows. The Commission has since withdrawn this directive and it is not
addressed in the proposed standard.65 To the extent this issue relates to commercial practices,
NAESB may consider this issue in its standards process.
Effective Date of MOD-030-2: In Order No. 729, the Commission noted that MOD-030-2
defines its effective date with reference to the effective date of MOD-030-1.66 The Commission
directed NERC to make the effective date explicit in any future versions of MOD-030-2 or any
other Reliability Standard. The Commission has since withdrawn this directive and it is not

65

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶
61,147 at PP 25-26, Attachment A (2013).
66

Order No. 729 at P 269.

36

addressed in the proposed standard.67 In any event, the effective date for proposed MOD-001-2 is
explicit and does not reference any earlier version of the Reliability Standard.
Modifications to Defined Terms: The Commission directed NERC to clarify or modify the
following terms used in the Existing MOD A Standards: “Postback,” “Business Practices” and
“ATC Path.”68 Because none of these terms are used in the proposed Reliability Standard, the
standard drafting team did not address these directives. Removal of, or revisions to, these terms
will be addressed in a subsequent standards development project related to the NERC Glossary.
To the extent that these terms are used in NAESB’s standards, NAESB may consider whether there
is a need to clarify the meaning of those terms.
D.

Enforceability of Proposed MOD-001-2

The proposed Reliability Standard includes VRFs and VSLs. The VRFs and VSLs provide
guidance on the way that NERC will enforce the requirements of the proposed Reliability
Standard. The VRFs and VSLs for the proposed Reliability Standard comport with NERC and
Commission guidelines related to their assignment. For a detailed review of the VRFs, the VSLs,
and the analysis of how the VRFs and VSLs were determined using these guidelines, please see
Exhibit F.
The proposed Reliability Standard also includes measures that support each requirement
by clearly identifying what is required and how the requirement will be enforced. These measures
help ensure that the requirements will be enforced in a clear, consistent, and non-preferential
manner and without prejudice to any party.69

67

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 145 FERC ¶
61,147 at PP 25-26, Attachment A (2013).
68

Order No. 729 at PP 304, 305, 306.

69

See Order No. 672 at P 327.

37

V.

EFFECTIVE DATE
As described in the Implementation Plan, attached hereto as Exhibit B, NERC respectfully

requests that the Commission approve the proposed Reliability Standard and the retirement of the
Existing MOD A Standards effective on the first day of the first calendar quarter that is 18 months
after the date that the proposed Reliability Standard is approved by FERC. The proposed
implementation period is intended to provide NAESB sufficient time to include in its WEQ
Standards, prior to the effective date of proposed MOD-001-2 and the retirement of the Existing
MOD A Standards, those elements from the Existing MOD A Standards, if any, that relate to
commercial or business practices and are not included in proposed MOD-001-2. Should NAESB
and its members determine that elements from the Existing MOD A Standards need to be
incorporated into the WEQ Standards, 18 months provides NAESB time, working through its
business practice development process, to adopt revised WEQ Standards and for the Commission
to incorporate by reference those revised WEQ Standards into its regulations. To the extent that
the proposed implementation period does not provide NAESB sufficient time to consider the
issues, NERC is committed to working with NAESB and Commission staff to address any timing
issues. NERC has requested that NAESB adopt any revised WEQ Standards to become effective
on the same date that the proposed MOD-001-2 and the retirement of the Existing MOD A
Standards will become effective.

38

VI.

CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission:


approve proposed Reliability Standard MOD-001-2 and associated elements included
in Exhibit A, effective as proposed herein;



approve the implementation plan included in Exhibit B; and



approve the retirement of Reliability Standards MOD-001-1, MOD-004-1, MOD-0081, MOD-028-2, MOD-029-1a AND MOD-030-2, effective as proposed herein.
Respectfully submitted,
/s/ S. Shamai Elstein
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Assistant General Counsel
S. Shamai Elstein
Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
[email protected]
[email protected]
[email protected]
Counsel for the North American Electric Reliability
Corporation

Date: February 10, 2014

39

Exhibit A
Proposed Reliability Standard

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
A. Introduction

1.

Title:

Available Transmission System Capability

2.

Number:

MOD-001-2

3.

Purpose:
To ensure that determinations of available transmission system capability are
determined in a manner that supports the reliable operation of the Bulk-Power
System (BPS) and that the methodology and data underlying those determinations are
disclosed to those registered entities that need such information for reliability
purposes.

4.

Applicability:
4.1. Functional Entity
4.1.1 Transmission Operator
4.1.2 Transmission Service Provider
4.2. Exemptions: The following is exempt from MOD-001-2.
4.2.1 Functional Entities operating within the Electric Reliability Council of
Texas (ERCOT)

5.

Effective Date:
5.1. The standard shall become effective on the first day of the first calendar quarter
that is 18 months after the date that the standard is approved by an applicable
governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to
go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first
calendar quarter that is 18 months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.

Page 1 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
B. Requirements and Measures

R1.

Each Transmission Operator that determines Total Flowgate Capability (TFC) or Total Transfer
Capability (TTC) shall develop a written methodology (or methodologies) for determining TFC or TTC
values. The methodology (or methodologies) shall reflect the Transmission Operator’s current
practices for determining TFC or TTC values. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
1.1 Each methodology shall describe the method used to account for the following limitations in
both the pre- and post-contingency state:
1.1.1

Facility ratings;

1.1.2

System voltage limits;

1.1.3

Transient stability limits;

1.1.4

Voltage stability limits; and

1.1.5

Other System Operating Limits (SOLs).

1.2 Each methodology shall describe the method used to account for each of the following
elements, provided such elements impact the determination of TFC or TTC:
1.2.1

The simulation of transfers performed through the adjustment of generation, Load, or
both;

1.2.2

Transmission topology, including, but not limited to, additions and retirements;

1.2.3

Expected transmission uses;

1.2.4

Planned outages;

1.2.5

Parallel path (loop flow) adjustments;

1.2.6

Load forecast; and

1.2.7

Generator dispatch, including, but not limited to, additions and retirements.

1.3 Each methodology shall describe the process for including any reliability-related constraints that
are requested to be included by another Transmission Operator, provided that (1) the request
references this specific requirement, and (2) the requesting Transmission Operator includes
those constraints in its TFC or TTC determination.
1.3.1 Each Transmission Operator that uses the Flowgate Methodology shall include in its
methodology an impact test process for including requested constraints. If a generator to
Load transfer in a registered entity’s area or a transfer to a neighboring registered entity
impacts the requested constraint by five percent or greater, the requested constraint
shall be included in the TFC determination, otherwise the requested constraint is not
required to be included.
1.3.2 Each Transmission Operator that uses the Area Interchange or Rated System Path
Methodology shall describe in its methodology the process it uses to account for
requested constraints that have a five percent or greater distribution factor for a transfer

Page 2 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
between areas in the TTC determination; otherwise the requested constraint is not
required to be included. When testing transfers involving the requesting Transmission
Operator’s area, the requested constraint may be excluded.
1.3.3 A different method for determining whether requested constraints need to be included
in the TFC or TTC determination may be used if agreed to by the Transmission Operators.
M1. Each Transmission Operator that determines TFC or TTC shall provide its current written
methodology (or methodologies) or other evidence (such as written documentation) to show that its
methodology (or methodologies) contains the following:


A description of the method used to account for the limits specified in part 1.1. Methods of
accounting for these limits may include, but are not limited to, one or more of the following:
o TFC or TTC being determined by one or more limits.
o Simulation being used to find the maximum TFC or TTC that remains within the limit.
o The application of a distribution factor in determining if a limit affects the TFC or TTC value.
o Monitoring a subset of limits and a statement that those limits are expected to produce the
most severe results.
o A statement that the monitoring of a select limit(s) results in the TFC or TTC not exceeding
another set of limits.
o A statement that one or more of those limits are not applicable to the TFC or TTC
determination.



A description of the method used to account for the elements specified in part 1.2, provided such
elements impact the determination of TFC or TTC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:
o A statement that the element is not accounted for since it does not affect the determination
of TFC or TTC.
o A description of how the element is used in the determination of TFC or TTC.

R2.



A description of the process for including any reliability-related constraints that are requested to
be included by another Transmission Operator, as specified in parts 1.3, 1.3.1, 1.3.2, or 1.3.3).



Each Transmission Operator that determines TFC or TTC shall provide evidence that currently
active TFC or TTC values were determined based on its current written methodology, as specified
in Requirement R1.

Each Transmission Service Provider that determines Available Flowgate Capability (AFC) or Available
Transfer Capability (ATC) shall develop an Available Transfer Capability Implementation Document
(ATCID) that describes the methodology (or methodologies) for determining AFC or ATC values. The
methodology (or methodologies) shall reflect the Transmission Service Provider’s current practices
for determining AFC or ATC values. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]

Page 3 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
2.1. Each methodology shall describe the method used to account for the following elements,
provided such elements impact the determination of AFC or ATC:
2.1.1.

The simulation of transfers performed through the adjustment of generation, Load, or
both;

2.1.2.

Transmission topology, including, but not limited to, additions and retirements;

2.1.3.

Expected transmission uses;

2.1.4.

Planned outages;

2.1.5.

Parallel path (loop flow) adjustments;

2.1.6.

Load forecast; and

2.1.7.

Generator dispatch, including, but not limited to, additions and retirements.

2.2. Each Transmission Service Provider that uses the Flowgate Methodology shall, for reliabilityrelated constraints identified in part 1.3, use the AFC determined by the Transmission Service
Provider for that constraint.
M2. Each Transmission Service Provider that determines AFC or ATC shall provide its current ATCID or
other evidence (such as written documentation) to show that its ATCID contains the following:


A description of the method used to account for the elements specified in part 2.1, provided such
elements impact the determination of AFC or ATC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:
o A description of how the element is used in the determination of AFC or ATC.
o A statement that the element is not accounted for since it does not affect the determination
of AFC or ATC.
o A statement that the element is accounted for in the determination of TFC or TTC by the
Transmission Operator, and does not otherwise affect the determination of AFC or ATC.

R3.



For each Transmission Service Provider that uses the Flowgate Methodology, a description of the
method in which AFC provided by another Transmission Service Provider was used for the
reliability-related constraints identified in part 1.3.



Each Transmission Service Provider that determines AFC or ATC shall provide evidence that
currently active AFC or ATC values were determined based on its current written methodology, as
specified in Requirement R2.

Each Transmission Service Provider that determines Capacity Benefit Margin (CBM) values shall
develop a Capacity Benefit Margin Implementation Document (CBMID) that describes its method for
determining CBM values. The method described in the CBMID shall reflect the Transmission Service
Provider’s current practices for determining CBM values. [Violation Risk Factor: Lower] [Time
Horizon: Operations Planning]

M3. Each Transmission Service Provider that determines CBM shall provide evidence, including, but not
limited to, its current CBMID, current CBM values, or other evidence (such as written
documentation, study reports, or supporting information) to demonstrate that it determined CBM
Page 4 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
values consistent with its methodology described in the CBMID. If a Transmission Service Provider
does not maintain CBM, examples of evidence include, but are not limited to, an attestation,
statement, or other documentation that states the Transmission Service Provider does not maintain
CBM.
R4.

Each Transmission Operator that determines Transmission Reliability Margin (TRM) values shall
develop a Transmission Reliability Margin Implementation Document (TRMID) that describes its
method for determining TRM values. The method described in the TRMID shall reflect the
Transmission Operator’s current practices for determining TRM values. [Violation Risk Factor:
Lower][Time Horizon: Operations Planning]

M4. Each Transmission Operator that determines TRM shall provide evidence including, but not limited
to, its current TRMID, current TRM values, or other evidence (such as written documentation, study
reports, or supporting information) to demonstrate that it determined TRM values consistent with
its methodology described in the TRMID. If a Transmission Operator does not maintain TRM,
examples of evidence include, but are not limited to, an attestation, statement, or other
documentation that states the Transmission Operator does not maintain TRM.
R5.

Within 45 calendar days of receiving a written request that references this specific requirement
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission Planner,
Transmission Service Provider, or any other registered entity that demonstrates a reliability need,
each Transmission Operator or Transmission Service Provider shall provide: [Violation Risk Factor:
Lower] [Time Horizon: Operations Planning]
5.1.

A written response to any request for clarification of its TFC or TTC methodology, ATCID,
CBMID, or TRMID. If the request for clarification is contrary to the Transmission Operator’s
or Transmission Service Provider’s confidentiality, regulatory, or security requirements then
a written response shall be provided explaining the clarifications not provided, on what basis
and whether there are any options for resolving any of the confidentiality, regulatory, or
security concerns.

5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s
effective:
5.2.1 TRMID; and
5.2.2 TFC or TTC methodology.

5.3.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s
effective:
5.3.1 ATCID; and
5.3.2 CBMID.

M5. Examples of evidence include, but are not limited to:
 Dated records of the request and the Transmission Operator’s or Transmission Service
Provider’s response to the request;

Page 5 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
 A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests; or
 A statement by the Transmission Operator or Transmission Service Provider that they do not
determine one or more of these values: AFC, ATC, CBM, TFC, TTC or TRM.
R6.

Each Transmission Operator or Transmission Service Provider that receives a written request from
another Transmission Operator or Transmission Service Provider for data related to AFC, ATC, TFC,
or TTC determinations that (1) references this specific requirement, and (2) specifies that the
requested data is for use in the requesting party’s AFC, ATC, TFC, or TTC determination shall take
one of the actions below. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
6.1. In responding to a written request for data on an ongoing basis, the Transmission Service
Provider or Transmission Operator shall make available its data on an ongoing basis no later
than 45 calendar days from receipt of the written request. Unless otherwise agreed upon, the
Transmission Operator or Transmission Service Provider is not required to:
6.1.1 Alter the format in which it maintains or uses the data; or
6.1.2 Make available the requested data on a more frequent basis than it produces the data
and in no event shall it be required to provide the data more frequently than once an
hour.
6.2 In responding to all other data requests, each Transmission Operator or Transmission Service
Provider shall make available the requested data within 45 calendar days of receipt of the
written request. Unless otherwise agreed upon, the Transmission Operator or Transmission
Service Provider is not required to alter the format in which it maintains or uses the data.
6.3 If making available any requested data under parts 6.1 or 6.2 of this requirement is contrary to
the Transmission Operator’s or Transmission Service Provider’s confidentiality, regulatory, or
security requirements, the Transmission Operator or Transmission Service Provider shall not
be required to make available that data; provided that, within 45 calendar days of the written
request, it responds to the requesting registered entity specifying the data that is not being
provided, on what basis and whether there are any options for resolving any of the
confidentiality, regulatory or security concerns.

M6. Examples of evidence for a data request that involves providing data on an ongoing basis (6.1),
include, but are not limited to:


Dated records of a registered entity’s request, and examples of the response being met;



Dated records of a registered entity’s request, and a statement from the requestor that the
request was met (demonstration that the response was met is not required if the requestor
confirms it is being provided); or



A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.

Examples of evidence for all other data requests (6.2) include, but are not limited to:


Dated records of a registered entity’s request, and the response to the request;

Page 6 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability


Dated records of a registered entity’s request, and a statement from the requestor that the
request was met; or



A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.

An example of evidence of a response by the Transmission Operator or Transmission Service
Provider that providing the data would be contrary to the registered entity’s confidentiality,
regulatory, or security requirements (6.3) is a response to the requestor specifying the data that is
not being provided, on what basis and whether there are any options for resolving any of the
confidentiality, regulatory, or security concerns.

Page 7 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
C. Compliance

1.

Compliance Monitoring Process:
1.1. Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” refers
to NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Evidence Retention:
The following evidence retention periods identify the period of time a registered entity
is required to retain specific evidence to demonstrate compliance. For instances in
which the evidence retention period specified below is shorter than the time since the
last audit, the Compliance Enforcement Authority may ask the registered entity to
provide other evidence to show that it was compliant for the full time period since the
last audit.


Implementation and methodology documents shall be retained for five years.



Components of the calculations and the results of such calculations for all values
contained in the implementation and methodology documents.
o Hourly values for the most recent 14 days;
o Daily values for the most recent 30 days; and
o Monthly values for the most recent 60 days.



If a Transmission Operator or Transmission Service Provider is found non-compliant,
it shall keep information related to the non-compliance until mitigation is complete
and approved.



The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Assessment Processes:


“Compliance Monitoring and Assessment Processes” refers to the identification of
the processes that will be used to evaluate data or information for the purpose of
assessing performance or outcomes with the associated reliability standard.

1.4. Additional Compliance Information:


None

Page 8 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Table of Compliance Elements
R#

R1

Time
Horizon
Operations
Planning

VRF

Lower

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for one of the
limitations listed in
part 1.1 in its written
methodology. (1.1)

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for two of the
limitations listed in
part 1.1 in its written
methodology. (1.1)

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for any of the
limitations listed in
part 1.1 in its written
methodology. (1.1)

Each Transmission
Operator that
determines TFC or TTC
did not develop a
written methodology
for describing its
current practices for
determining TFC or
TTC values.

OR

OR

OR

OR

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for one of the element
listed in part 1.2 in its
written methodology,
provided that element
impacts its TFC or TTC
determination. (1.2)

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for two, three, or four
elements listed in part
1.2 in its written
methodology,
provided those
elements impacts its
TFC or TTC
determination. (1.2)

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for five, six, or seven
elements of listed in
part 1.2 in its written
methodology,
provided those
elements impacts its
TFC or TTC
determination. (1.2)

Each Transmission
Operator that
determines TFC or TTC
developed a written
methodology for
determining TFC or
TTC but the
methodology did not
reflect its current
practices for
determining TFC or
TTC values.

OR
Page 9 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

Each Transmission
Operator that
determines TFC or TTC
has not described the
process for including
any reliability-related
constraints that have
been requested by
another Transmission
Operator, provided the
constraints are also
used in the requesting
Transmission
Operator’s TFC or TTC
calculation and the
request referenced
part 1.3. (1.3)
OR
Each Transmission
Operator that
determines TFC or TTC
has not used (i) an
impact test process for
including requested
constraints, (ii) a
process to account for
requested constraints
Page 10 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R2

Operations
Planning

Lower

Moderate VSL

High VSL

that have a five
percent or greater
distribution factor for
a transfer between
areas in the TTC
determination, or (iii) a
mutually agreed upon
method for
determining whether
requested constraints
need to be included in
the TFC or TTC
determination. (1.3.1,
1.3.2, 1.3.3)
Each Transmission
Each Transmission
Each Transmission
Service Provider that
Service Provider that
Service Provider that
determines AFC or ATC determines AFC or ATC determines AFC or ATC
has not described its
has not described its
has not described its
method for accounting method for accounting method for accounting
for one of the
for two, three, or four for five, six, or seven
elements listed in part elements listed in part elements listed in part
2.1 in its written
2.1 in its written
2.1 in its written
methodology,
methodology,
methodology,
provided that element provided the elements provided the elements
impacts its AFC or ATC impact its AFC or ATC
impact its AFC or ATC
determination. (2.1)
determination. (2.1)
determination. (2.1)
OR

Severe VSL

Each Transmission
Service Provider that
determines AFC or ATC
did not develop an
ATCID describing its
AFC or ATC
methodology.
OR
Each Transmission
Service Provider that
determines AFC or ATC
did not reflect its
current practices for
Page 11 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R3

Operations
Planning

Lower

None.

Moderate VSL

None.

High VSL
Each Transmission
Service Provider that
uses the Flowgate
Methodology did not
use the AFC
determined by the
Transmission Service
Provider for reliabilityrelated constraints
identified in part 1.3.
(2.2)
None.

Severe VSL
determining AFC or
ATC values in its
ATCID.

Each Transmission
Service Provider that
determines CBM
values did not develop
a CBMID describing its
method for
determining CBM
values.
OR
Each Transmission
Service Provider that
determines CBM
values did not reflect
its current practices
for determining CBM
values in its CBMID.
Page 12 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R4

Operations
Planning

Lower

None.

Moderate VSL
None.

High VSL
None.

Severe VSL
Each Transmission
Operator that
determines TRM
values did not develop
a TRMID describing its
method for
determining TRM
values.
OR

R5

Operations
Planning

Lower

Each Transmission
Operator that
determines TRM
values did not reflect
its current practices
for determining TRM
values in its TRMID.
Each Transmission
Each Transmission
Each Transmission
Each Transmission
Operator or
Operator or
Operator or
Operator or
Transmission Service
Transmission Service
Transmission Service
Transmission Service
Provider did not
Provider did not
Provider did not
Provider failed to
respond in writing to a respond in writing to a respond in writing to a respond in writing to a
written request by one written request by one written request by one written request by one
or more of the
or more of the
or more of the
or more of the
registered entities
registered entities
registered entities
registered entities
specified in
specified in
specified in
specified in
Requirement R5 within Requirement R5 within Requirement R5 within Requirement R5.
45 calendar days from 76 calendar days from 106 calendar days
Page 13 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R6

Operations
Planning

Lower

the date of the
request, but did
respond in writing
within 75 calendar
days.
Each Transmission
Operator or
Transmission Service
Provider did not
respond to a written
request for data by
one or more of the
registered entities
specified in
Requirement R6 by
making the requested
data available within
45 calendar days from
the date of the
request, but did
respond within 75
calendar days.

Moderate VSL
the date of the
request, but did
respond in writing
within 105 calendar
days.
Each Transmission
Operator or
Transmission Service
Provider did not
respond to a written
request for data by
one or more of the
registered entities
specified in
Requirement R6 by
making data available
within 76 calendar
days from the date of
the request, but did
respond within 105
calendar days.

High VSL

Severe VSL

from the date of the
request, but did
respond in writing
within 135 calendar
days.
Each Transmission
Operator or
Transmission Service
Provider did not
respond to a written
request by one or
more of the registered
entities specified in
Requirement R6 by
making data available
within 106 calendar
days from the date of
the request, but did
respond within 135
calendar days.

Each Transmission
Operator or
Transmission Service
Provider failed to
respond to a written
request for data by
making data available
to one or more of the
entities specified in
Requirement R6.

Page 14 of 18

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

D. Regional Variances

None.
E. Interpretations

None.
F. Associated Documents

None.

Page 15 of 18

Guidelines and Technical Basis
Guidelines and Technical Basis
Requirement R1:
Total Flowgate Capability (TFC) and Total Transfer Capability (TTC) are the starting points for
the Available Flowgate Capability (AFC) and Available Transfer Capability (ATC) values. AFC and
ATC values influence Real-time conditions and have the ability to impact Real-time operations.
A Transmission Operator (TOP) shall clearly document its methods of determining TFC and TTC
so that any TOP or Transmission Service Provider (TSP) that uses the information can clearly
understand how the values are determined. The TFC and TTC values shall account for any
reliability-related constraints that limit those values as well as system conditions forecasted for
the time period for which those values are determined. The TFC and TTC values shall also
incorporate constraints on external systems when appropriate, in addition to constraints on the
TOP’s own system. Requirement R1 sets requirements for the determination of TFC or TTC, but
does not establish if a TOP must determine TFC or TTC.
Requirement R2:
A TSP must clearly document its methods of determining AFC and ATC so that TOPs or other
entities can clearly understand how the values are determined. The AFC and ATC values shall
account for system conditions at the time those values would be used. Each TSP that uses the
Flowgate Methodology shall also use the AFC value determined by the TSP responsible for an
external system constraint where appropriate. Requirement R2 sets requirements for the
determination of AFC or ATC, but does not establish if a TSP must determine AFC or ATC.
Requirement R3:
Capacity Benefit Margin (CBM) is one of the values that may be used in determining the AFC or
ATC value. CBM is the amount of firm transmission transfer capability preserved by the
transmission provider for Load-Serving Entities (LSEs), whose Loads are located on that TSP’s
system, to enable access by the LSEs to generation from interconnected systems to meet
resource reliability requirements. A clear explanation of how the CBM value is developed is an
important aspect of the TSP’s ability to communicate to other entities how that AFC or ATC
value was determined. Therefore anytime CBM is used (non-zero) a CBMID is required to
communicate the method of determining CBM.
Requirement R4:
Transmission Reliability Margin (TRM) is one of the values that may be used in determining the
AFC or ATC value. TRM accounts for the inherent uncertainty in system conditions and the need
for operating flexibility to ensure reliable system operation as system conditions change. An
explanation by the TOP of how the TRM value is developed for use in the TSP’s determination
of AFC and ATC is an important aspect of the TSP’s ability to communicate to other entities how
that AFC or ATC value was determined. Therefore, anytime a TOP provides a non-zero TRM to a
TSP, a Transmission Reliability Margin Implementation Document (TRMID) is required to
communicate the method of determining TRM.

Page 16 of 18

Guidelines and Technical Basis
Requirement R5:
Clear communication of the methods of determining AFC, ATC, CBM, TFC, TRM, and TTC are
necessary to the reliable operation of the Bulk-Power System (BPS). A TOP and TSP are
obligated to make available their methodologies for determining AFC, ATC, CBM, TFC, TRM, and
TTC to those with a reliability need. The TOP and TSP are further obligated to respond to any
requests for clarification on those methodologies, provided that responding to such requests
would not be contrary to the registered entities confidentiality, regulatory, or security
concerns. The purpose of this requirement is not to monitor every communication that occurs
regarding these values, but to ensure that those with reliability need have access to the
information. Therefore, the requirement is very specific on when it is invoked so that it does
not create an administrative burden on regular communications between registered entities.
Rationale for R6:
This requirement provides a mechanism for each TOP or TSP to access the best available data
for use in its calculation of AFC, ATC, CBM, TFC, TRM, and TTC values. Requirement R6 requires
that a TOP or TSP share their data, with the caveat that the TOP or TSP is not required to modify
that data from the form that they use or maintain it in. For data requests that involve providing
data on a regular interval, the TOP or TSP is not obligated to provide the data more frequently
than either (1) once an hour, or (2) as often as they update the data. The data provider is also
not obligated to provide data that would violate any of its confidentiality, regulatory, or security
obligations. The purpose of this requirement is not to monitor every data exchange that occurs
regarding these values, but to ensure that those with reliability need have access to the
information. Therefore, the requirement is very specific on when it is invoked so that it does
not create an administrative burden on regular communications between registered entities.

Page 17 of 18

Guidelines and Technical Basis
Version History

Version

Date

Action

1

August 26,
2008

Adopted by the NERC Board
of Trustees

1a

November 5,
2009

Adopted by the NERC Board
of Trustees

2

February 6,
2014

Adopted by the NERC Board
of Trustees

Change Tracking

Interpretation
(Project 2009-15)
Consolidation of MOD-0011a, MOD-004-1, MOD-008-1,
MOD-028-1, MOD-029-1a,
and MOD-030-2

Page 18 of 18

Exhibit B
Implementation Plan

Implementation Plan
Project 2012-05 MOD A
Implementation Plan for MOD-001-2 – Available Transmission System Capability
Approvals Required
MOD-001-2 – Available Transmission System Capability
Prerequisite Approvals
There are no other standards that must receive approval prior to the approval of this standard.
Revisions to Glossary Terms
None
Applicable Entities
Transmission Operator
Transmission Service Provider
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
The standard shall become effective on the first day of the first calendar quarter that is 18 months
after the date that the standard is approved by an applicable governmental authority or as otherwise
provided for in a jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not required,
the standard shall become effective on the first day of the first calendar quarter that is 18 months after
the date the standard is adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.
Justification
The proposed 18-month implementation period is designed to allow the North American Energy
Standards Board (NAESB) to include in its Wholesale Electric Quadrant Standards for Business Practices
and Communication Protocols for Public Utilities (WEQ Standards), prior to the effective date of

proposed MOD-001-2 and the retirement of currently effective Reliability Standards MOD-001-1, MOD004-1, MOD-008-1, MOD-028-2, MOD-029-1a and MOD-030-2 (MOD A Standards), those elements
from the MOD A Standards that relate to commercial or business practices and are not included in
proposed MOD-001-2. NERC and the standard drafting team recognize that even though certain of the
requirements in the MOD A Standards do not address reliability issues and, in turn, are not included in
proposed MOD-001-2, those requirements may be essential for market or commercial purposes and
should be considered by an organization, like NAESB, that administers business practice standards for
the electric industry.
The proposed implementation period should provide NAESB sufficient time, working through its
business practice development process, to adopt revised WEQ Standards to include the commercial
elements of the MOD A Standards and for the Federal Energy Regulatory Commission to incorporate by
reference the revised WEQ Standards into its regulations. NERC expects that NAESB will adopt revised
WEQ Standards to become effective on the same date as the proposed MOD-001-2 and the retirement
of the MOD A Standards will become effective.
Retirements
MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and MOD-030-2 shall be retired at
midnight of the day immediately prior to the effective date of MOD-001-2. The effective retirement
date should coincide with the effective date of revised WEQ Standards adopted by NAESB.

Project 2012-05 ATC Revisions
October 4, 2013

2

Exhibit C
Order No. 672 Criteria

EXHIBIT C
Order No. 672 Criteria
In Order No. 672,1 the Commission identified a number of criteria it will use to analyze
Reliability Standards proposed for approval to ensure they are just, reasonable, not unduly
discriminatory or preferential, and in the public interest. The discussion below identifies these
factors and explains how the proposed Reliability Standard has met or exceeded the criteria:
1. Proposed Reliability Standards must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve that goal.2
The proposed Reliability Standard achieves the specific reliability goal of ensuring that
determinations of Available Transfer Capability (“ATC”) and Available Flowgate Capability
(“AFC”) and their components – Total Transfer Capability (“TTC”) or Total Flowgate
Capability (“TFC”), Existing Transmission Commitments (“ETC”), Capacity Benefit Margins
(“CBM”), and Transmission Reliability Margins (“TRM”) – are accomplished in a manner that
supports the reliable operation of the Bulk Power System. ATC and AFC values are commercial
in nature, representing the amount of unused transmission capacity that a Transmission Service
Provider is willing to make available for sale to third parties to accommodate additional requests
for transmission service. To ensure that such determinations do not impact reliable operations,
the proposed Reliability Standard requires that ATC and AFC values (1) account for applicable
system limits and relevant system conditions, and (2) are determined in a transparent manner
such that planners and operators of the Bulk-Power System maintain awareness of available

1

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. & Regs. ¶
31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).
2

Order No. 672 at PP 321, 324.

transmission system capability and future flows on their own systems as well as pertinent
neighboring systems.
2. Proposed Reliability Standards must be applicable only to users, owners and
operators of the bulk power system, and must be clear and unambiguous as to what
is required and who is required to comply.3
The proposed Reliability Standard is clear and unambiguous as to what is required and
who is required to comply, in accordance with Order No. 672. The proposed Reliability
Standard applies to Transmission Service Providers and Transmission Operators that determine
ATC, AFC, TTC, TFC, CBM and/or TRM. The proposed Reliability Standard clearly articulates
the actions that such entities must take to comply with the standard.
3. A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation.4
The Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) for the
proposed Reliability Standard comport with NERC and Commission guidelines related to their
assignment. The assignment of the severity level for each VSL is consistent with the
corresponding requirement and the VSLs should ensure uniformity and consistency in the
determination of penalties. The VSLs do not use any ambiguous terminology, thereby
supporting uniformity and consistency in the determination of similar penalties for similar
violations. For these reasons, the proposed Reliability Standard includes clear and
understandable consequences in accordance with Order No. 672.

3

Order No. 672 at PP 322, 325.

4

Order No. 672 at P 326.

4. A proposed Reliability Standard must identify clear and objective criterion or
measure for compliance, so that it can be enforced in a consistent and nonpreferential manner. 5
The proposed Reliability Standard contains measures that support each requirement by
clearly identifying what is required and how the requirement will be enforced. These measures
help provide clarity regarding the manner in which the requirements will be enforced, and help
ensure that the requirements will be enforced in a clear, consistent, and non-preferential manner
and without prejudice to any party.
5. Proposed Reliability Standards should achieve a reliability goal effectively and
efficiently — but do not necessarily have to reflect “best practices” without regard
to implementation cost or historical regional infrastructure design.6
The proposed Reliability Standard achieves the reliability goal effectively and efficiently
in accordance with Order No. 672. By exclusively focusing on the reliability issues associated
with ATC and AFC determinations, the proposed Reliability Standard represents a more
effective and efficient approach to addressing the reliability concerns associated with such
determinations than currently exists in NERC’s Reliability Standards.
6. Proposed Reliability Standards cannot be “lowest common denominator,” i.e.,
cannot reflect a compromise that does not adequately protect Bulk-Power System
reliability. Proposed Reliability Standards can consider costs to implement for
smaller entities, but not at consequences of less than excellence in operating system
reliability.7
The proposed Reliability Standard does not reflect a “lowest common denominator”
approach. To the contrary, the proposed Reliability Standard represents a significant
improvement over the existing standards pertaining to ATC/AFC. The proposed Reliability

5

Order No. 672 at P 327.

6

Order No. 672 at P 328.

7

Order No. 672 at P 329-30.

Standard requires that an entity’s methodologies be documented and available to others and that
those methodologies account for factors, like system limits, necessary to protect reliability.
7. Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability Standard while
not favoring one geographic area or regional model. It should take into account
regional variations in the organization and corporate structures of transmission
owners and operators, variations in generation fuel type and ownership patterns,
and regional variations in market design if these affect the proposed Reliability
Standard.8
The proposed Reliability Standard applies throughout North America and does not favor
one geographic area or regional model. In fact, the proposed Reliability Standard supports the
various ways in which ATC and AFC are determined across the continent.
8. Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability.9
The proposed Reliability Standard has no undue negative impact on competition. The
standard does not restrict ATC/AFC or limit use of the Bulk-Power System in a preferential
manner. In fact, the changes in the proposed Reliability Standard are designed, in part, to ensure
that NERC’s Reliability Standards do not address or impact market issues.
9. The implementation time for the proposed Reliability Standard is reasonable.10
The proposed effective date for the standard is just and reasonable. Because the proposed
Reliability Standard removes many requirements from the existing ATC-related standards that
may be relevant to commercial or market practices, NERC has requested that the North
8

Order No. 672 at P 331.

9

Order No. 672 at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to the effect
of a proposed Reliability Standard on competition. The ERO should attempt to develop a proposed Reliability
Standard that has no undue negative effect on competition. Among other possible considerations, a proposed
Reliability Standard should not unreasonably restrict available transmission capability on the Bulk-Power System
beyond any restriction necessary for reliability and should not limit use of the Bulk-Power System in an unduly
preferential manner. It should not create an undue advantage for one competitor over another.
10

Order No. 672 at P 333.

American Energy Standards Board (“NAESB”) consider whether any of those requirements
should be adopted into its Wholesale Electric Quadrant Standards for Business Practices and
Communication Protocols for Public Utilities (the “WEQ Standards”).

The proposed

implementation plan is designed to allow NAESB sufficient time to include in its WEQ
Standards, prior to the effective date of proposed MOD-001-2 and the retirement of the currently
effective MOD A Standards, those elements from the MOD A Standards that relate to
commercial or business practices and are not included in proposed MOD-001-2. The
implementation period also provides time for NERC registered entities to make any changes in
their internal process necessary to implement MOD-001-2. The proposed effective dates are
explained in the proposed Implementation Plan, attached as Exhibit B.
10. The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard development
process.11
The proposed Reliability Standard was developed in accordance with NERC’s
Commission-approved, ANSI- accredited processes for developing and approving Reliability
Standards. Exhibit F includes a summary of the Reliability Standard development proceedings,
and details the processes followed to develop the Reliability Standards. These processes
included, among other things, comment and balloting periods. Additionally, all meetings of the
drafting team were properly noticed and open to the public. The initial and additional ballots
achieved a quorum and exceeded the required ballot pool approval levels.

11

Order No. 672 at P 334.

11. NERC must explain any balancing of vital public interests in the development of
proposed Reliability Standards.12
NERC has identified no competing public interests regarding the request for approval of
the proposed Reliability Standard. No comments were received that indicated the proposed
Reliability Standard conflicts with other vital public interests.
12. Proposed Reliability Standards must consider any other appropriate factors.13
No other negative factors relevant to whether the proposed Reliability Standard is just
and reasonable were identified.

12

Order No. 672 at P 335.

13

Order No. 672 at P 323.

Exhibit D
Mapping Document

Project 2012-05 Mapping Document

Transition of MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and
MOD-030-2 to Proposed MOD-001-2
The below mapping document provides information on how the approved requirements within MOD-001-a, MOD-004-1, MOD-008-1,
MOD-028-1, MOD-029-1a, and MOD-030-2 transition into the proposed MOD-001-1. As a general statement, the reliability-based
components of those Reliability Standards are captured in MOD-001-2 while non-reliability-based components will be transition out of the
NERC Reliability Standards. Where a prescriptive existing requirement does not easily map into the proposed MOD-001-2, a description and
change justification is provided.

Requirement in
Approved Standard

MOD-001-1a R1

MOD-001-1a R2
MOD-001-1a R2.1
MOD-001-1a R2.2
MOD-001-1a R2.3

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed Reliability Standard requires disclosure of the method
used to calculate Available Transfer Capability (ATC) but no longer
Requirement R2
requires a registered entity to select a method explicitly described in
the NERC Reliability Standards.
The proposed Reliability Standard will require disclosure of calculation
Requirement R2
frequency but does not specify the range of required calculations.
Requirement R2
See comments on Requirement R2.
Requirement R2
See comments on Requirement R2.
Requirement R2
See comments on Requirement R2.

Requirement in
Approved Standard

MOD-001-1a R3

MOD-001-1a R3.1
MOD-001-1a R3.2
MOD-001-1a R3.2.1
MOD-001-1a R3.2.2
MOD-001-1a R3.3

MOD-001-1a R3.4

MOD-001-1a R3.5
MOD-001-1a R3.6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R2 of the proposed Reliability Standard retains the
obligation to have an Available Transfer Capability Implementation
Requirement R2
Document (ATCID) that reflects its method for calculating Available
Flowgate Capability (AFC) or ATC.
This information would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirements R2 & R5
Requirement R2 and may be addressed under Requirement R5 in
response to a request for clarification.
This rationale would be included within the ATCID created under
Requirement R2
Requirement R2.
This information would be included within the ATCID created under
Requirement R2
Requirement R2.
The identity of the TSPs and Transmission Operators (TOPs) for which it
provides data is captured when a registered entity formally requests
Requirements R5 &R6.
that information under Requirements R5 or R6 of the proposed
Reliability Standard.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.

2

Requirement in
Approved Standard
MOD-001-1a R3.6.1
MOD-001-1a R3.6.2
MOD-001-1a R3.6.3
MOD-001-1a R4
MOD-001-1a R4.1
MOD-001-1a R4.2
MOD-001-1a R4.3
MOD-001-1a R4.4
MOD-001-1a R4.5
MOD-001-1a R4.6
MOD-001-1a R5

MOD-001-1a R6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
The requirement for a Transmission Service Provider (TSP) to notify
registered entities when a change is made to its ATCID is an
administrative burden and provides little to no reliability benefit.
Requirement R5
Posting on its company website or Open Access Same-Time
Information System (OASIS) provides notice that a change has been
made. Although not specifically required under the proposed Reliability
Standards, a registered entity may continue to provide such notice.
Requirement R5 of the proposed Reliability Standard obligates the TSP
Requirement R5 for an ATCID provided upon
to provide its ATCID to any registered entity that needs it for reliability
formal request.
upon request.
Ensuring that ATC, Total Transfer Capability (TTC), Available Flowgate
Capability (AFC), and Total Flowgate Capability (TFC) calculations use
assumptions no more limiting than those used in the planning of
The Requirement has been retired.
operations does not serve a clear reliability goal. The ATCID will have a
description of how ATC, TTC, AFC, or TFC is calculated, with sufficient
detail to allow for a comparison.

3

Requirement in
Approved Standard

MOD-001-1a R7

MOD-001-1a R8
MOD-001-1a R8.1
MOD-001-1a R8.2
MOD-001-1a R8.3
MOD-001-1a R9
MOD-001-1a R9.1
MOD-001-1a R9.1.1
MOD-001-1a R9.1.2
MOD-001-1a R9.1.3
MOD-001-1a R9.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Ensuring that ATC, TTC, AFC, and TFC calculations use assumptions no
more limiting then those used in the planning of operations does not
The Requirement has been retired.
serve a clear reliability goal. The ATCID will have a description of how
ATC, TTC, AFC, or TFC is calculated, with sufficient detail to allow for a
comparison.
The reliability component of ATC is disclosure of a registered entity’s
practice which is still captured, but not the performance aspect of the
The Requirement has been retired.
ATC calculations. Mandating the frequency with which ATC is
calculated does not serve a reliability benefit.
The Requirement has been retired.
See comments on Requirement R8.
The Requirement has been retired.
See comments on Requirement R8.
The Requirement has been retired.
See comments on Requirement R8.
Requirement R6 of the proposed Reliability Standard requires a TOP or
TSP, within 45 calendar days of receiving a written request, to make
available the data or explain why it is not doing so due to
confidentiality, regulatory, or security concerns.
See comments for Requirement R9.
Requirement R5
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.

4

Requirement in
Approved Standard

MOD-004-1 R1
MOD-004-1 R1.1
MOD-004-1 R1.2
MOD-004-1 R1.3
MOD-004-1 R2

MOD-004-1 R3
MOD-004-1 R3.1
MOD-004-1 R3.2
MOD-004-1 R4
MOD-004-1 R4.1
MOD-004-1 R4.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed standard will require registered entities that use Capacity
Benefit Margin (CBM) to have a Capacity Benefit Margin (CBMID) that
Requirement R3
reflects its current practices for determining CBM. The proposed
Reliability Standard does not dictate how CBM must be calculated.
Requirement R3
See comments above.
Requirement R3
See comments above.
Requirement R3
See comments above.
Requirement R5 of the proposed Reliability Standard requires TSPs to
Requirement part R5.2.2
share its CBMID with entities that request it and have a reliability need
for that data.
The applicability of the proposed Reliability Standard has been changed
so that the LSE is not an applicable registered entity within the
Requirement R3
Reliability Standard. The method by which a TSP determines CBM will
be included in its CBMID.
Requirement R3
See comment above.
Requirement R3
See comment above.
The applicability of the proposed Reliability Standard has been changed
so that the Resource Planner (RP) is not an applicable registered entity
The Requirement has been retired.
within the Reliability Standard. The method by which a TSP determines
CBM will be included in its CBMID.
The Requirement has been retired.
See comment above.
The Requirement has been retired.
See comment above.

5

Requirement in
Approved Standard
MOD-004-1 R5
MOD-004-1 R5.1
MOD-004-1 R5.2

MOD-004-1 R6
MOD-004-1 R6.1
MOD-004-1 R6.2

MOD-004-1 R7

MOD-004-1 R8

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed Reliability Standard will require TSPs that use CBM to
Requirement R3
have a CBMID but does not specify what must be included or how it is
calculated.
The proposed standard will require TSPs that use CBM to have a CBMID
Requirement R3
but does not specify what must be included or how it is calculated.
The proposed standard will require TSPs that use CBM to have a CBMID
Requirement R3
but does not specify what must be included or how it is calculated.
The applicability of the proposed standard has been changed so that
the Transmission Planner (TP) is not an applicable registered entity
The Requirement has been retired.
within the standard. The method by which a TSP determines CBM will
be included in its CBMID.
The Requirement has been retired.
See comment above.
The Requirement has been retired.
See comment above.
The proposed standard does not explicitly require that the TSP to notify
Load-Serving Entities (LSEs) and RPs of the amount of CBM set aside.
The SDT determined this requirement provided little to no reliability
The Requirement has been retired.
benefit. The proposed Reliability Standard only requires the TSP to have
a CBMID and make that available to other registered entities, including
LSEs and RPs.
The applicability of the proposed Reliability Standard has been changed
The Requirement has been retired.
so that the TP is not an applicable registered entity within the Reliability
Standard.

6

Requirement in
Approved Standard
MOD-004-1 R9
MOD-004-1 R9.1
MOD-004-1 R9.2
MOD-004-1 R10

MOD-004-1 R11

MOD-004-1 R12

MOD-004-1 R12.1

MOD-004-1 R12.2

MOD-004-1 R12.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The new Requirement R6 requires TSPs to share the data used in CBM
Requirement R6
calculations with registered entities that have a reliability need for that
data. TPs are not longer subject to the Reliability Standard.
Requirement R6
See comment above.
Requirement R6
See comment above.
The applicability of the proposed Reliability Standard has been changed
The Requirement has been retired.
so that the LSE or Balancing Authority (BA) are not applicable registered
entities within the Reliability Standard.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.

7

Requirement in
Approved Standard
MOD-008-1 R1

MOD-008-1 R1.1
MOD-008-1 R1.2
MOD-008-1 R1.3
MOD-008-1 R1.3.1
MOD-008-1 R1.3.2
MOD-008-1 R1.3.3
MOD-008-1 R2

MOD-008-1 R3
MOD-008-1 R4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R4
Requirement R4 requires a TRMID that reflects the TOPs current
practices for determining TRM. The proposed Reliability Standard does
not dictate how TRM must be calculated as such detail provides little to
no reliability benefit.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4 requires a TRMID that describes how TRM values are
determined. Prescribing that the value must come from a predefined
Requirement R4
list of uncertainties or that the value does not double count with CBM
does not provide any reliability benefit.
Requirements R5 and R6 require disclosure of TRMID and underlying
Requirement R5
data upon request if not already posted on OASIS or similar site.
Requirement R4 requires a TRMID that includes the frequency of
Requirement R4
updating; setting an arbitrary date to recalculate TRM does not
contribute to reliability.

8

Requirement in
Approved Standard

MOD-008-1 R5

Requirement in
Approved Standard

MOD-028-1 R1

MOD-028-1 R1.1
MOD-028-1 R1.2
MOD-028-1 R1.3
MOD-028-1 R1.4
MOD-028-1 R1.5
MOD-028-1 R1.5.1
MOD-028-1 R1.5.2
MOD-028-1 R1.5.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R2 and R4, the ATCID and TRMID respectively, would
contain information on how the value is shared and on what frequency.
Requirements R2 & R4
Setting an arbitrary frequency is unnecessary to meet the reliability
goal of disclosure.

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1 requires a TOP to have a written methodology for
determining TTC or TFC. Requirement R2 requires a TSP to have an
Requirements R1 & R2
ATCID that describes how ATC or AFC is determined, which would
include any parts of the TTC/TFC development not covered by a TOP
under Requirement R1.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

9

Requirement in
Approved Standard
MOD-028-1 R1.5.4
MOD-028-1 R2

MOD-028-1 R2.1

MOD-028-1 R2.2

MOD-028-1 R2.3

MOD-028-1 R3

MOD-028-1 R3.1
MOD-028-1 R3.1.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
Requirements R1 & R2
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
Requirements R1 & R2
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice. In addition, R1 requires the TOP to use
Requirements R1 & R2
the defined facility ratings and SOL's, as appropriate, to determine the
TTC value.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1, Part 1.2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

10

Requirement in
Approved Standard
MOD-028-1 R3.1.2
MOD-028-1 R3.1.2
MOD-028-1 R3.2
MOD-028-1 R3.2.1
MOD-028-1 R3.2.2
MOD-028-1 R3.2.2
MOD-028-1 R4
MOD-028-1 R4.1

MOD-028-1 R4.2

MOD-028-1 R4.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 set this obligation upon the TOP and TSP,
Requirements R1 & R2
respectively.
Requirements R1 and R2 require disclosure of practice, which is the
reliability need for this requirement. Verification that a contract is being
Requirements R1 & R2
followed is primarily a commercial issue and not a NERC Reliability
issue.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and Requirement R1
specifically addresses documentation of their process and reliability
points. The remainder of the material in the requirement provides
Requirement R1, Part 1.2
instructions on determining TTC, which is not necessary within a NERC
requirement to protect reliability. The TTC methodology will describe
how these services are used and any necessary clarifications can be
sought under Requirement R5. Having a long list of methods of
incorporating these service did not contribute to reliability.

11

Requirement in
Approved Standard
MOD-028-1 R5

MOD-028-1 R5.1

MOD-028-1 R5.2
MOD-028-1 R5.3
MOD-028-1 R6

MOD-028-1 R6.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
calculation will be discussed within the ATCID and driven by either
Requirements R1 & R2
reliability or market needs, whichever provides for a tighter time frame.
The required periodicity of a TFC or TTC calculation is a method and
region specific issue, and it is not necessary to reliability to specify such
a value.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
Requirement R1 and Parts 1.1 and 1.2.1
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.

12

Requirement in
Approved Standard

MOD-028-1 R6.2

MOD-028-1 R6.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
Requirements R1, Part 1.2.1
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
Requirements R1
calculating TTC does not support a reliability need. The new Reliability
Standard does not prevent "Sum of Facility Ratings" as a limit on the
path, however it does not prescribe it either. "Sum of Facility Ratings"
is a commercial concept; the reliability aspect was addressed in
determining the Incremental Transfer Capability (ITC).

13

Requirement in
Approved Standard

MOD-028-1 R6.4

MOD-028-1 R7

MOD-028-1 R7.1

MOD-028-1 R7.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
Requirements R1
calculating TTC does not support a reliability need. Contractual rights
imply there is already a contract and obligation in place, there is no
reliability benefit in NERC monitoring this contract. The Reliability
Standard does not prevent this from being a limit, but does not
prescribe it either
This requirement serves no direct purpose other than serving as a
Requirement R1
bridge to the requirement parts below.
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
Requirement R1 & R6
requirement addresses. The frequency of disclosure is set by
agreement with the TSP or other factors, and there is no reliability
benefit in setting an arbitrary frequency of providing the value.
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
Requirement R1 & R6
requirement addresses. The frequency of disclosure is set by
agreement with the TSP or other factors, and there is no reliability
benefit in setting an arbitrary frequency of providing the value.

14

Requirement in
Approved Standard

MOD-028-1 R8

MOD-028-1 R9

MOD-028-1 R10

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement is primarily a definition of what Existing Transfer
Commitments (ETC) is and does not provide for system reliability.
Breaking ETC into its component parts is a guide for determining ETC
This Requirement has been retired.
but does not establish a reliability requirement. Under their
agreements with which the transmission commitments are made the
registered entity is obligated to respect those commitments and there
is no need for NERC to monitor this commercial arrangement.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This Requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
Requirements R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This Requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that
Requirements R10 and R11 just provided additional educational
reference to ATC, but did not establish a reliability requirement.

15

Requirement in
Approved Standard

MOD-028-1 R11

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
and the NERC Glossary of Terms defines ATC. Beyond that
This Requirement has been retired.
Requirements R10 and R11 just provided additional educational
reference on what ATC was but did not establish a reliability
requirement.

16

Requirement in
Approved Standard
MOD-029-1a R1

MOD-029-1a R1.1

MOD-029-1a R1.1.1
MOD-029-1a R1.1.1.1
MOD-029-1a R1.1.1.2
MOD-029-1a R1.1.1.3
MOD-029-1a R1.1.2
MOD-029-1a R1.1.3
MOD-029-1a R1.1.4
MOD-029-1a R1.1.5
MOD-029-1a R1.1.6
MOD-029-1a R1.1.7
MOD-029-1a R1.1.8
MOD-029-1a R1.1.9
MOD-029-1a R1.1.10

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirements R1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

17

Requirement in
Approved Standard
MOD-029-1a R1.2
MOD-029-1a R2

MOD-029-1a R2.1

MOD-029-1a R2.1.1

MOD-029-1a R2.1.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Part 1.1 describes the method used to account for
Requirement R1, Part 1.1
Facility Ratings as well as system voltage, transient stability, voltage
stability, and other SOLs.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1, Part 1.2, Requirement R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirement R1 specifically requires the TOP to respect transmission
element ratings, Requirements R1 and R2 requires disclosure of the
TOP and TSP's practices in this regard. The revised Reliability Standard
does not go into detail to require that the starting case for an analysis
Requirement R1, Parts 1.1 & 1.2,
meet these criteria. Requirement R1, Part 1.1 requires that TTC
Requirement R2
accounts for these elements, but does not require that the starting case
meet the criteria described under MOD-029 Requirement R2, Part 2.1.
Trying to list this detail would require a textbook level description of
the process and would not set a reliability goal.
Requirement R1, Parts 1.1 & 1.2,
See comment above.
Requirement R2

18

Requirement in
Approved Standard
MOD-029-1a R2.1.3

MOD-029-1a R2.2

MOD-029-1a R2.3

MOD-029-1a R2.4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Parts 1.1 & 1.2,
See comment above.
Requirement R2
This is not a reliability requirement but a business practice to provide
for some sort of result when a reliability constraint can't be reached.
This requirement part has been retired.
This level of information is appropriate in an instructional context but is
not a reliability requirement. The current Requirement R1 requires the
TOP to describe how it does this, but does not prescribe a method.
As the name implies, there is already an obligation between the parties
to respect a value and Requirement R1 just requires that TTC not
Requirements R1 & R2
exceed reliability limits, it does not rule out a lower limit due to
contractual obligations. There is no reliability benefit to NERC
monitoring to ensure that contractual obligations are met.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
This requirement part has been retired
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.

19

Requirement in
Approved Standard

MOD-029-1a R2.5

MOD-029-1a R2.6

MOD-029-1a R2.7

MOD-029-1a R2.8

MOD-029-1a R3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
This requirement part has been retired.
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
As the name implies, there is already an obligation between the parties
to respect a value and Requirement R1 just requires that TTC not
Requirements R1 & R2
exceed reliability limits, it does not rule out a lower limit due to
contractual obligations. There is no reliability benefit to NERC
monitoring to ensure that contractual obligations are met.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
Requirements R1 & R2
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirements R1 and R2 address this need by requiring a methodology,
Requirements R1 & R2
and in the effort to demonstrate that the methodology was followed
the necessary reports will be developed.
Requirement R1, Part 1.1 requires that SOLs be accounted for in the
Requirements R1 & R2
method used in determining TTC. Requirement R2 requires disclosure
of practices for determining ATC.

20

Requirement in
Approved Standard

MOD-029-1a R4

MOD-029-1a R5

MOD-029-1a R6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
requirement addresses. The frequency of disclosure is set by
agreement with the TSP considering individual facts and circumstances,
Requirements R1, R5, & R6
and there is no reliability benefit in setting an arbitrary frequency of
providing the value. Requirement R6 requires disclosure of data and
Requirement R5 requires disclosure of methods and responding to
requests for clarification.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.

21

Requirement in
Approved Standard

MOD-029-1a R7

MOD-029-1a R8

Requirement in
Approved Standard
MOD-030-2 R1

MOD-030-2 R1.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R7 and R8 do not appear verbatim in the new Reliability
Standard; however, Requirement R2 will require disclosure and the
This requirement has been retired.
NERC Glossary of Terms defines ATC. Beyond that Requirements R7 and
R8 just provided additional educational reference on what ATC was but
did not establish a reliability requirement.
Requirements R7 & R8 do not appear verbatim in the new Reliability
Standard; however, Requirement R2 will require disclosure and the
This requirement has been retired.
NERC Glossary of Terms defines ATC. Beyond that Requirements R7 and
R8 just provided additional educational reference on what ATC was but
did not establish a reliability requirement.
Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This is a summary of the requirement parts and does not in itself
Requirements R1 & R2
establish and obligation.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.

22

Requirement in
Approved Standard
MOD-030-2 R1.2
MOD-030-2 R1.2.1
MOD-030-2 R1.2.2
MOD-030-2 R1.2.3
MOD-030-2 R1.2.4
MOD-030-2 R2
MOD-030-2 R2.1

MOD-030-2 R2.1.1

MOD-030-2 R2.1.1.1
MOD-030-2 R2.1.1.2
MOD-030-2 R2.1.1.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.3 requires each methodology to describe the
process for including any reliability-related constraints requested to be
included by another TOP based on if the requesting TOP includes those
constraints in its TFC or TTC determination. Furthermore, Requirement
R1, Part 1.3.1 states that each TOP that uses the Flowgate methodology
Requirement R1, Parts 1.3 & 1.3.1
shall include in its methodology an impact test process for including
requested constraints. If a generator to Load transfer in a registered
entity’s area or a transfer to a neighboring registered entity impact the
requested constraint by five percent or greater, the requested
constraint shall be included in the TFC determination, otherwise the
requested constraint is not required to be included.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.

23

Requirement in
Approved Standard
MOD-030-2 R2.1.2
MOD-030-2 R2.1.2.1
MOD-030-2 R2.1.2.2
MOD-030-2 R2.1.2.3
MOD-030-2 R2.1.3
MOD-030-2 R2.1.4
MOD-030-2 R2.1.4.1
MOD-030-2 R2.1.4.2
MOD-030-2 R2.2
MOD-030-2 R2.3
MOD-030-2 R2.4

MOD-030-2 R2.5

MOD-030-2 R2.5.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
This requirement part has been retired.
The required periodicity of updating a list is not of a reliability benefit.
This requirement part has been retired.
The required periodicity of updating a list is not of a reliability benefit.
Requirement R1, Part 1.1 requires that SOLs be accounted for in the
Requirement R1, Part 1.1 & Requirement R2 method used in determining TTC. Requirement R2 requires disclosure
of practices for determining ATC.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
Requirements R1 & R2
calculation will be discussed within the ATCID and driven by either
reliability or market needs whichever provides for a tighter time frame.
The frequency of disclosure is set by agreement with the TSP
considering the individual facts and circumstances, and there is no
This requirement part has been retired.
reliability benefit in setting an arbitrary frequency of providing the
value.

24

Requirement in
Approved Standard

MOD-030-2 R2.6
MOD-030-2 R3
MOD-030-2 R3.1
MOD-030-2 R3.2
MOD-030-2 R3.3
MOD-030-2 R3.4
MOD-030-2 R3.5

MOD-030-2 R4

MOD-030-2 R5

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The frequency of disclosure is set by agreement with the TSP
considering the individual facts and circumstances, and there is no
This requirement part has been retired.
reliability benefit in setting an arbitrary frequency of providing the
value.
Requirement R6
Requirement R6 requires data sharing.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirements R1, part 1.1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.

25

Requirement in
Approved Standard

MOD-030-2 R5.1

MOD-030-2 R5.2
MOD-030-2 R5.3

MOD-030-2 R6

MOD-030-2 R6.1
MOD-030-2 R6.1.1
MOD-030-2 R6.1.2
MOD-030-2 R6.2
MOD-030-2 R6.2.1
MOD-030-2 R6.2.2
MOD-030-2 R6.3
MOD-030-2 R6.4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
Requirements R1 & R2
R1. Specifically, Requirement R2, Part 2.2 requires each TSP that uses
the Flowgate Methodology to use the AFC determined by the TSP for
reliability constraints identified in Requirement R1, Part 1.3.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.

26

Requirement in
Approved Standard
MOD-030-2 R6.5
MOD-030-2 R6.6
MOD-030-2 R6.7
MOD-030-2 R7
MOD-030-2 R7.1
MOD-030-2 R7.2
MOD-030-2 R7.3
MOD-030-2 R7.4
MOD-030-2 R7.5
MOD-030-2 R7.6
MOD-030-2 R7.7

MOD-030-2 R8

MOD-030-2 R9

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

27

Requirement in
Approved Standard

MOD-030-2 R10

MOD-030-2 R10.1

MOD-030-2 R10.2

MOD-030-2 R10.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
Requirement R2
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

28

Requirement in
Approved Standard

MOD-030-2 R11

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
Requirement R2
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

New Requirements not found in existing MOD standards
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
N/A
N/A

Project 2012-05 ATC Revisions
October 4, 2013

Description and Change Justification
N/A

29

Exhibit E
Consideration of Directives

Project 2012-05 - ATC Revisions (MOD A)
Consideration of Directives (November 12, 2013)
Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10204 – Order No. 729 at P 129
129. If the Commission determines upon its own review of the data,
or upon review of a complaint, that it should investigate the
implementation of the available transfer capability methodologies,
the Commission will need access to historical data. Accordingly,
pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, the Commission directs the ERO to modify the Reliability
Standards so as to increase the document retention requirements to a
term of five years, in order to be consistent with the enforcement
provisions established in Order No. 670.

1

(2000)).

Consideration of Directive
Consistent with FERC’s directive, proposed MOD-001-2 requires
applicable registered entities to retain the implementation and
methodology documents required under Requirements R1-R4 for
five years. For the components of the calculations and the results of
such calculations for all values contained in the implementation
and methodology documents, the proposed standard provides a
graduated time frame for the calculations of hourly, daily, and
monthly values. Evidence of hourly values must be retained for 14
days, daily values for 30 days and monthly values for 60 days. The
standard drafting team (“SDT”) concludes there is little to no
benefit of requiring entities to retain such detailed supporting data
of the calculations for longer periods. The SDT notes that to comply
with Commission requirements under Order No. 670,1 however,
entities may be required to retain such supporting data for longer
periods.

Prohibition of Energy Market Manipulation, Order No. 670, 71 FR 4244 (Jan. 26, 2006), FERC Stats. & Regs. ¶ 31,202, at PP 62- 63 (2006) (citing 28 U.S.C. § 2462

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10206 – Order No. 729 at P 151
151. Nevertheless, the Commission believes that the lists of required
recipients of the implementation documents may be overly
prescriptive and could exclude some registered entities with a
reliability need to review such information. Accordingly, pursuant to
section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop a modification to the
Reliability Standards pursuant to the ERO’s Reliability Standards
development process to require disclosure of the various
implementation documents to any registered entity who
demonstrates to the ERO a reliability need for such information.

VRF and VSL Justifications

Consideration of Directive
Consistent with the Commission’s directive, Requirement R5 of the
proposed standard requires that the implementation documents be
made available to any registered entity that demonstrates a
reliability need for such information, subject to confidentiality,
regulatory, and security requirements.

2

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10207 – Order No. 729 at P 160
160. In Order No. 890, the Commission also expressed concern
regarding the treatment of reservations with the same point of receipt
(generator), but multiple points of delivery (Load), in setting aside
existing transmission capacity. The Commission found that such
reservations should not be modeled in the existing transmission
commitments calculation simultaneously if their combined reserved
transmission capacity exceeds the generator’s nameplate capacity at
the point of receipt. The Commission required the development of
Reliability Standards that lay out clear instructions on how these
reservations should be accounted for by the transmission service
provider. The proposed Reliability Standards achieve this by requiring
transmission service providers to identify in their implementation
documents how they have implemented MOD-028-1, MOD-029-1, or
MOD-030-2, including the calculation of existing transmission
commitments. Thus we will not direct the ERO to develop a
modification to address over-generation, as suggested by Entegra.
Nonetheless, in developing the modifications to the MOD Reliability
Standards directed in this Final Rule, the ERO should consider
generator nameplate ratings and transmission line ratings including
the comments raised by Entegra and ISO/RTO Council.

2

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed reliability standard. First, in a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.2 Additionally, the SDT concludes that the comments
regarding generator nameplate ratings and transmission line
ratings do not relate to the reliability issues associated with
Available Flowgate Capability (AFC) and Available Transfer
Capability (ATC) calculations. The SDT notes that the comments
relate to the determination of existing transmission commitments
(ETC), which is a component of ATC or AFC that would be disclosed
in an entity’s Available Transfer Capability Implementation
Document (ATCID) under Requirement R2 of the proposed
standard. Specifying the manner in which ETC is determined, which
would include generator nameplate ratings and transmission line
ratings, where appropriate, is not necessary for reliability purposes.
NERC is working with the North American Energy Standards Board
(NAESB) to transfer those elements from the MOD A standards that
relate to commercial or business practices and are not included in
proposed MOD-001-2 into NAESB’s business practice standards.
When considering whether to incorporate those elements into its
business practice standards, NAESB could consider whether it is
appropriate to address this directive.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

3

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10208 – Order No. 729 at P 162
162. In Order No. 890, the Commission directed public utilities,
working through NERC, to modify MOD-010 through MOD-025 to
incorporate a periodic review and modification of various data
models. The Commission found that updating and benchmarking was
essential to accurately simulate the performance of the transmission
grid and to calculate comparable available transfer capability values.
On rehearing, the Commission clarified that the models used by the
transmission provider to calculate available transfer capability, and
not actual available transfer capability values, must be benchmarked.
Updating and benchmarking of models to actual events will ensure
greater accuracy, which will benefit information provided to and used
by adjacent transmission service providers who rely upon such
information to plan their systems. Accordingly, pursuant to section
215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop benchmarking and updating
requirements to measure modeled available transfer and flowgate
capabilities against actual values. Such requirements should specify
the frequency for benchmarking and updating the available transfer
and flowgate capability values and should require transmission service
providers to update their models after any incident that substantially
alters system conditions, such as generation outages.

VRF and VSL Justifications

Consideration of Directive
The SDT concludes that the proposed standard is responsive to the
Commission’s concern regarding the accuracy of ATC/AFC values as
system conditions change. Requirements R1 (part 1.2) and R2 (part
2.1) of the proposed standard require that a Transmission
Operator’s (TOP’s) and a Transmission Service Providers (TSP’s)
models for determining Total Flowgate Capability (TFC) or Total
Transfer Capability (TTC) or AFC/ATC, respectively, account for
system topology, including additions and retirements as well as
expected system usage, planned outages, Load forecast and
expected generation dispatch when such elements impact the
determination of TFC, TTC, AFC or ATC. By describing how its
methodology accounts for these elements, adjacent systems will be
able to effectively model their own transfer or flowgate capabilities.
The SDT concludes, however, that because each part of the country
has a different sensitivity to these elements and the frequency with
which they change, there is no additional reliability benefit in
mandating the frequency with which a TOP or TSP must benchmark
or update its models. Under Requirement R6 of the proposed
standard, registered entities are required to share their data with
others, which also increases the amount of up to date information
available for the determination of AFC/ATC values. Additionally,
under Requirements R5 of the proposed standard, a TSP or a TOP
could be asked to clarify its benchmarking or updating practices, if
not already set forth in its documented methodology, and share
data underling those practices. As such, the proposed reliability
addresses the Commission’s directive toward increasing accuracy by
improving transparency.

4

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10209 – Order No. 729 at P 173
173. The Commission therefore directs the ERO, pursuant to section
215(d)(5) of the FPA and section 39.5(f) of our regulations, to develop
a modification to MOD-028-1 and MOD-029-1 to specify that base
generation schedules used in the calculation of available transfer
capability will reflect the modeling of all designated network
resources and other resources that are committed to or have the legal
obligation to run, as they are expected to run, and to address the
effect on available transfer capability of designating and
undesignating a network resource.

NERC S-Ref 10211 – Order No. 729 at P 179
179. We agree that, in order to be useful, hourly, daily and monthly
available transfer capability and available flowgate capability values
must be calculated and posted in advance of the relevant time period.
Requirement R8 of MOD-001-1 and Requirement R10 of MOD-030-2
require that such posting will occur far enough in advance to meet this
need. With respect to Entegra’s request regarding more frequent
updates for constrained facilities, we direct the ERO to consider this
suggestion through its Reliability Standards development process.

3

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. The SDT concludes that this directive
does not relate to the reliability issues associated with ATC or AFC
determinations. Specifically, the directive relates to the inputs for
calculating ETC, which is not relevant to reliability. The SDT
concludes that there is no reliability purpose served by mandating
how generation and network resources should be treated so long
as it is transparent. The SDT notes that under Requirement R2 of
the proposed standard, a TSP should describe its practices related
to the treatment of base generation schedules and the effect of
designating and undesignating a network resource. Under
Requirement R5 of the proposed reliability standard, the TSP will be
required to respond to requests for clarification of its practices on
this issue. The SDT notes that NAESB could consider whether to
address this directive from a commercial perspective.
The SDT determines that it is not necessary to address this directive
in the proposed standard. In a recent Notice of Proposed
Rulemaking, the Commission proposed to withdraw this directive.3
Additionally, the SDT concludes that the frequency of updates for
constrained facilities is not relevant to reliability but relates to
commercial access to the constrained paths. The SDT notes,
however, that an entity’s ATCID should address this issue. NAESB
could consider whether to address this directive from a commercial
perspective.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

5

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10212 – Order No. 729 at P 179
179. Further, we agree with Cottonwood regarding unscheduled or
unanticipated events. Therefore, pursuant to section 215(d)(5) of the
FPA and section 39.5(f) of our regulations, we direct the ERO to
develop modifications to MOD-001-1 and MOD-030-2 to clarify that
material changes in system conditions will trigger an update whenever
practical. Finally, we clarify that these Reliability Standards shall not
be used as a “safe harbor” to avoid other, more stringent reporting or
update requirements.
NERC S-Ref 10214 – Order No. 729 at P 184
184. As proposed, MOD-001-1 does not restrict a transmission service
provider from double-counting data inputs or assumptions in the
calculation of available transfer or flowgate capability. To the extent
possible, available transfer or flowgate capability values should reflect
actual system conditions. The double-counting of various data inputs
and assumptions could cause an understatement of available transfer
or flowgate capability values and, thus, poses a risk to the reliability of
the Bulk-Power System. We note that, in the Commission’s order
accepting the associated NAESB business standards, issued
concurrently with this Final Rule in Docket No. RM05-5-013, the
Commission directs EPSA to address its concerns regarding the
modeling of condition firm service through the NERC Reliability
Standards development process. We reaffirm here that modeling of
available transfer capability should consider the effects of conditional
firm service, including the potential for double-counting. Accordingly,
pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, the Commission directs the ERO to develop modifications
to MOD-001-1 pursuant to the ERO’s Reliability Standards
development process to prevent the double-counting of data inputs
and assumptions. In developing these modifications, the ERO should
consider the effects of conditional firm service.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. The proposed standard is limited to
addressing reliability issues associated with AFC/ATC
determinations. The need to update due to material changes in
system condition is not needed for reliability but serves the
purpose of providing the best information to the market. As such, it
may be appropriate for NAESB to address this issue in its business
practice standards. The SDT notes, however, that an entity’s ATCID
could address this issue.
The SDT concludes that the proposed standard is responsive to the
Commission’s concern. By requiring the documentation and
disclosure of the methodologies for determining TTC/TFC, AFC/ATC,
Capacity Benefit Margin (CBM) and Transmission Reliability Margin
(TRM), registered entities will understand how a neighboring entity
calculates these values and, in turn, reduces the reliability risks
associated with potentially double-counting any data inputs and
assumptions. NAESB may also consider whether the possibility of
double-counting needs to be addressed in greater detail in its
business practice standards.

6

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10215 – Order No. 729 at P 192
192. In its filing letter, NERC states that it requires applicable entities
to calculate available transfer capability or available flowgate
capability on a consistent schedule and for specific time frames. In
keeping with the Commission’s goals of consistency and transparency
in the calculation of available transfer capability or available flowgate
capability, the Commission finds that transmission service providers
should use consistent modeling practices over different time frames. If
a transmission service provider uses inconsistent modeling practices
over different time frames that should be made explicit in its
implementation document along with a justification for the
inconsistent practices. Accordingly, pursuant to section 215(d)(5) of
the FPA and section 39.5(f) of our regulations, the Commission directs
the ERO to develop a modification to the Reliability Standard pursuant
to its Reliability Standards development process requiring
transmission service providers to include in their implementation
documents any inconsistent modeling practices along with a
justification for such inconsistencies.

VRF and VSL Justifications

Consideration of Directive
The SDT concludes that the proposed standard is responsive to the
Commission’s concern. By requiring that TSPs and TOPs document
their methodologies for determining TTC/TFC, AFC/ATC, CBM and
TRM to reflect their current practices, the TSP/TOP must provide
information regarding their modeling practices, including whether
those modeling practices are used consistently. Additionally,
Requirement R5 allows registered entities to request that the
TSP/TOP clarify its methodology, which includes requests about the
TSP’s/TOP’s modeling practices. Should NAESB see a need for
additional detail on modeling practices for purposes of ensuring a
non-discriminatory market, it may further consider this directive.

7

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10216 – Order No. 729 at P 200
200. With regard to Midwest ISO’s concern, while the terms
“assumptions” and “no more limiting” as used in Requirements R6
and R7 could benefit from further granularity, we find these
Requirements to be sufficiently clear for purposes of compliance.
Likewise, with regard to Entegra’s concern, we agree that
transmission service providers should use data and assumptions for
their available transfer capability or available flowgate capability and
total transfer capability or total flowgate capability calculations that
are consistent with those used in the planning of operations and
system expansion. Under Requirements R6 and R7, transmission
service providers and transmission operators must not overstate
assumptions that are used in planning of operations. We believe these
requirements are sufficiently clear as written. Nonetheless, we
encourage the ERO to consider Midwest ISO’s and Entegra’s
comments when developing other modifications to the MOD
Reliability Standards pursuant to the ERO’s Reliability Standards
development procedure.

4

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. In a recent Notice of Proposed
Rulemaking, the Commission proposed to withdraw this directive.4
There is no additional reliability benefit to specifically including a
requirement that the TOP explain how it uses consistent or less
limiting assumptions than their operations planning. This issue may
be considered further by NAESB if it is important for commercial
purposes.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

8

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10217 – Order No. 729 at P 220
220. We agree with NERC that a transmission service provider should
consider any information provided in establishing an appropriate level
of capacity benefit margin. Similarly, we agree with the Georgia
Companies that all relevant information should be considered in
establishing an appropriate level of capacity benefit margin, including
information provided by customers. However, in determining the
appropriate generation capacity import requirement as part of the
sum of capacity benefit margin to be requested from the transmission
service provider, it would not be appropriate for a load-serving entity
or resource planner to rely exclusively on a reserve margin or
adequacy requirement established by an entity that is not subject to
this Standard. Thus, we hereby adopt the NOPR proposal to direct the
ERO to develop a modification to Requirements R3.1 and R.4.1 of
MOD-004-1 to require load-serving entities and resource planners to
determine generation capability import requirements by reference to
one or more relevant studies (loss of load expectation, loss of load
probability or deterministic risk analysis) and applicable reserve
margin or resource adequacy requirements, as relevant. Such a
modification should ensure that a transmission service provider has
adequate information to establish the appropriate level of capacity
benefit margin.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. Under the proposed
standard, the method of calculating CBM is determined by the TSP
and must be described in the TSP’s CBMID. The SDT concludes that
no reliability benefit is provided by placing a requirement on Load
Serving Entities (LSEs) and Resource Planners (RPs) to determine
generation capability import requirements by reference to one or
more relevant studies and applicable reserve margin or resource
adequacy requirements. This issue may be considered further by
NAESB if it is important for commercial purposes.

9

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10218 – Order No. 729 at P 222
222. We agree with the Midwest ISO that ISOs, RTOs, and other
entities with a wide view of system reliability needs should be able to
provide input into determining the total amount of capacity benefit
margin required to preserve the reliability of the system. However,
Requirements R1.3 and R7 already make clear that determinations of
need for generation capability import requirement made by a load
serving entity or resource planner are not final. Further, the third
bullet of Requirements R5 and R6 explicitly lists reserve margin or
resource adequacy requirements established by RTOs and ISOs among
the factors to be considered in establishing capacity benefit margin
values for available transfer capability paths or flowgates used in
available transfer capability or available flowgate capability
calculations. In fact, it is for this reason that we uphold the NOPR
proposal. Therefore, pursuant to section 215(d)(5) of the FPA and
section 39.5(f) of our regulations, the Commission directs the ERO to
modify MOD-004-1 to clarify the term “manage” in Requirement R1.3.
This modification should ensure that the Reliability Standard clarify
how the transmission service provider will manage situations where
the requested use of capacity benefit margin exceeds the capacity
benefit margin available.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. Under the proposed
reliability standard, the method of calculating CBM is determined
by the TSP and must be described in the TSP’s CBMID. The Capacity
Benefit Margin Implementation Document (CBMID) should describe
the manner in which the TSP will manage situations where the
requested use of CBM exceeds the CBM available. The SDT
concludes that no reliability benefit is provided specifically
requiring such a description. This issue may be considered further
by NAESB if it is important for commercial purposes.

10

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10219 – Order No. 729 at P 231
231. The Commission understands sub-requirement R2.2 of MOD-0281 to mean that, when calculating total transfer capability for available
transfer capability paths, a transmission operator shall use a
transmission model that includes relevant data from reliability
coordination areas that are not adjacent. While we believe that the
provision is reasonably clear, the Commission agrees that the term
“and beyond” could be better explained. Accordingly, pursuant to
section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop a modification subrequirement R2.2 pursuant to its Reliability Standards development
process to clarify the phrase “adjacent and beyond Reliability
Coordination areas.”
NERC S-Ref 10220 - Order No. 729 at P 234
234. The Commission believes that, as written, the time frames
established in Requirement R5 are just and reasonable because they
balance the need to reliably operate the grid with the burden on
transmission operators to recalculate total transfer capability even
when total transfer capability does not often change. Nevertheless,
the Commission agrees that a graduated time frame for reposting
could be reasonable in some situations. Accordingly, the ERO should
consider this suggestion when making future modifications to the
Reliability Standards.

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.5 Additionally, the proposed standard does not use the
phrase “adjacent and beyond Reliability Coordination areas.”

The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.6 The SDT considered this issue and concludes that there
is no reliability benefit in requiring specific time frames for an Area
Interchange Methodology user to update their TTC based on an
outage. Under the proposed reliability standard, the time frame
within which a value is recalculated and reposted based on an
outage would be addressed by the TOP in its methodology. This
issue may be considered further by NAESB if it is important for
commercial purposes.

5

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

6

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

11

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10221 – Order No. 729 at P 237
237. The Commission agrees that any distribution factor to be used
should be clearly stated in the implementation document, and that to
facilitate consistent and understandable results the distribution
factors used in determining total transfer capability should be applied
consistently. Accordingly, pursuant to section 215(d)(5) of the FPA
and section 39.5(f) of our regulations, the Commission directs the ERO
to develop a modification to MOD-028-1 pursuant to its Reliability
Standards development process to address these two concerns.

NERC S-Ref 10222 – Order No. 729 at P 246
246. Puget Sound’s request is reasonable, and insofar as calculating
non-firm available transfer capability using counterschedules as
opposed to counterflows achieves substantially equivalent results,
using them will not be considered a violation. However, we do not
have enough information to determine that the terms are generally
interchangeable in all circumstances. The ERO should consider Puget
Sound’s concerns on this issue when making future modifications to
the Reliability Standards.

7

Consideration of Directive
The SDT concludes that the proposed reliability standard is
responsive to the Commission’s concern. First, the proposed
reliability standard requires disclosure of the TOP’s method of
addressing TTC/TFC and the TSP’s method of determining ATC/AFC.
These methods will describe the manner in which TOPs and TSPs
use distribution factors. The description must reflect current
practices. The proposed standard also allows neighboring TOPs to
request that a TOP consider a transmission constraint in its TTC/TFC
determination. Users of the Area Interchange or Rated System Path
Methodology must describe the process they use to account for
requested constraints that have a five percent or greater
distribution factor for a transfer between areas in the TTC
determination.
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.7 Additionally, the SDT concludes that the issue raised by
Puget Sound is outside the scope of the reliability issues associated
with ATC/AFC determinations.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

12

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10223 – Order No. 729 at P 269
269. As noted above, the Commission approves the proposal to make
these Reliability Standards effective on the first day of the first
calendar quarter that is twelve months beyond the date that the
Reliability Standards are approved by all applicable regulatory
authorities. Although MOD-030-2 defines its effective date with
reference to the effective date of MOD-030-1, the Commission finds
that this direction is sufficiently clear in the context of the current
proceeding. To the extent necessary, we clarify MOD-030-2 shall
become effective on the first day of the first calendar quarter that is
twelve months beyond the date that the Reliability Standards are
approved by all applicable regulatory authorities. The Commission
also directs the ERO to make explicit such detail in any future version
of this or any other Reliability Standard.
NERC S-Ref 10226 – Order No. 729 at P 304
304. The Commission believes that the definition of Postback is not
fully determinative. NERC should be able to define this term without
reference to the Business Practices, another defined term.
Accordingly, the Commission adopts its NOPR proposal and directs the
ERO to develop a modification to the definition of Postback to
eliminate the reference to Business Practices. Although we are
sensitive to Puget Sound’s concern that the required Postback
component may increase the recordkeeping burden on some entities,
in other regions the component may be critical. We disagree that the
term’s existence assumes that once a reservation is confirmed on a
particular point of reservation or point of receipt combination the
impact of the confirmed reservation will always be present in the
available transfer capability calculation. However, we would consider
suggestions that would allow entities to comply with the
requirements as efficiently as possible, such as a regional difference
through the ERO’s standards development procedure.

8

Consideration of Directive
The SDT determines that this directive is no longer relevant.
Additionally, in a recent Notice of Proposed Rulemaking, the
Commission proposed to withdraw this directive.8

Because the term “Postback” is not used in the proposed standard,
it is not necessary to address this directive. The term “Postback” is
not used in any other standard. Any necessary revisions to NERC’s
Glossary of Terms to remove the term “Postback” will be addressed
in a subsequent project modifying the NERC Glossary.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

13

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10227 – Order No. 729 at P 305
305. The Commission also adopts its NOPR proposal to direct the ERO
to develop a modification to the definition of Business Practices that
would remove the reference to regional reliability organizations and
replace it with the term Regional Entity. We also direct the ERO to
develop a definition of the term Regional Entity to be included in the
NERC Glossary.
NERC S-Ref 10229 – Order No. 729 at P 306
306. We agree with SMUD and Salt River that the definition of “ATC
Path” should not limit a transmission provider’s flexibility to treat
multiple parallel interconnections between balancing authorities as a
single path, and that available transfer capability paths may comprise
multiple, parallel interconnections between Balancing Authorities
when such treatment is appropriate to maintain reliability. We also
agree that the definition should not reference the Commission’s
regulations. The Commission’s regulations are not applicable to all
registered entities and are subject to change. We therefore direct the
ERO to develop a modification to the definition of “ATC Path” that
does not reference the Commission’s regulations.

VRF and VSL Justifications

Consideration of Directive
Because the term “Business Practices” is not used in the proposed
standard, it is not necessary to address this directive. Any
necessary revisions to NERC’s Glossary of Terms related to the term
“Business Practices” will be part of any subsequent project
modifying the NERC Glossary

Because the term “ATC Path” is not used in the proposed standard,
it is not necessary to address this directive. The term “ATC Path” is
not used in any other standard. Any necessary revisions to NERC’s
Glossary of Terms to remove the term “ATC Path” will be part of
any subsequent project modifying the NERC Glossary.

14

Exhibit F
Analysis of Violation Risk Factors and Violation Security Levels

Violation Risk Factor and Violation Severity Level Justifications
MOD-001-2 – Available Transmission System Capability

This document provides the Standard Drafting Team’s (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in MOD-001-2 – Available Transmission System Capability. Each requirement is assigned a VRF and a VSL.
These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of requirements in
FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the
following NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project.
NERC Criteria - Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric
System at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to
effectively monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric
System instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk
Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric
System instability, separation, or cascading failures, nor to hinder restoration to a normal condition.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement
that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.
FERC Violation Risk Factor Guidelines
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified areas
appropriately reflect their historical critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk-Power System:
• Emergency operations
• Vegetation management
• Operator personnel training
• Protection systems and their coordination
• Operating tools and backup facilities
• Reactive power and voltage control
• System modeling and data exchange
• Communication protocol and facilities
• Requirements to determine equipment ratings
• Synchronized data recorders
• Clearer criteria for operationally critical facilities

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

• Appropriate use of transmission loading relief.
Guideline (2) – Consistency within a Reliability Standard

The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main Requirement
Violation Risk Factor assignment.
Guideline (3) – Consistency among Reliability Standards

The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability goals in
different Reliability Standards would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s definition of
that risk level.
Guideline (5) –Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have
at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

Violation severity levels should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
Moderate VSL
High VSL
The performance or product
The performance or product
The performance or product
measured almost meets the full measured meets the majority of measured does not meet the
intent of the requirement.
the intent of the requirement.
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline 1 – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline 2 – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3 – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4 – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.

VRF and VSL Justifications – MOD-001-2, Requirement R1
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The reliability objective is for a Transmission Operator (TOP) to have a written methodology for
determining Total Transfer Capability (TTC) or Total Flowgate Capability (TFC), which are the starting
points for determinations of Available Transfer Capability (ATC) and Available Flowgate Capability (AFC).
Although AFC and ATC values influence Real‐time conditions and have the ability to impact Real‐time
operations, these values do not directly control the reliable operation of the Bulk-Power System.
Accordingly, a violation of this requirement would not be expected to adversely affect the electrical state
or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. A Lower VRF is thus appropriate.
Additionally, currently effective Reliability Standards MOD-001-1a, MOD-028-2, MOD-029-1a, and MOD030-2, which are being retired as part of this project, assign a Lower VRF to requirements addressing the
documentation of TTC/TFC methodologies. The proposed Lower VRF is thus consistent with the VRFs for
previous FERC approved requirements related to TTC/TFC determination.

FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion

VRF and VSL Justifications

Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
The Lower VRF is applicable to all parts of the requirement.
Guideline 3- Consistency among Reliability Standards

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R1
This requirement is similar to FERC approved MOD-028-2, Requirement R1 and MOD-029-1a, Requirement
R2, which deals with TTC and were assigned a VRF of Lower. MOD-028-2 and MOD-029-1a are replaced by
Requirement R1, and therefore the proposed Lower VRF is consistent with those in the previously
approved standards.

FERC VRF G4 Discussion

FERC VRF G5 Discussion

The VRF for Requirement R1 is also consistent with the Lower VRF assignment in FAC-013-2, which also
contains requirements for documenting transfer capability.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective, to ensure that a TOP documents its TTC or TFC
methodology and accounts for relevant operating limits and system conditions. Therefore, the
requirement has one VRF that is appropriate for its single obligation.
Proposed VSL

Lower

Moderate

Each Transmission Operator
that determines TFC or TTC has
not described its method for
accounting for one of the
limitations listed in part 1.1 in
its written methodology. (1.1)

Each Transmission Operator
that determines TFC or TTC has
not described its method for
accounting for two of the
limitations listed in part 1.1 in
its written methodology. (1.1)

High
Each Transmission Operator that
determines TFC or TTC has not
described its method for
accounting for any of the
limitations listed in part 1.1 in its
written methodology. (1.1)

Severe
Each Transmission Operator that
determines TFC or TTC did not
develop a written methodology for
describing its current practices for
determining TFC or TTC values.
OR

OR

VRF and VSL Justifications

OR

OR

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R1
Each Transmission Operator
that determines TFC or TTC has
not described its method for
accounting for one of the
element listed in part 1.2 in its
written methodology, provided
that element impacts its TFC or
TTC determination. (1.2)

Each Transmission Operator
that determines TFC or TTC has
not described its method for
accounting for two, three, or
four elements listed in part 1.2
in its written methodology,
provided those elements
impacts its TFC or TTC
determination. (1.2)

Each Transmission Operator that
determines TFC or TTC has not
described its method for
accounting for five, six, or seven
elements of listed in part 1.2 in its
written methodology, provided
those elements impacts its TFC or
TTC determination. (1.2)
OR
Each Transmission Operator that
determines TFC or TTC has not
described the process for including
any reliability-related constraints
that have been requested by
another Transmission Operator,
provided the constraints are also
used in the requesting
Transmission Operator’s TFC or
TTC calculation and the request
referenced part 1.3. (1.3)
OR

VRF and VSL Justifications

Each Transmission Operator that
determines TFC or TTC developed
a written methodology for
determining TFC or TTC but the
methodology did not reflect its
current practices for determining
TFC or TTC values.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R1
Each Transmission Operator that
determines TFC or TTC has not
used (i) an impact test process for
including requested constraints,
(ii) a process to account for
requested constraints that have a
five percent or greater distribution
factor for a transfer between areas
in the TTC determination, or (iii) a
mutually agreed upon method for
determining whether requested
constraints need to be included in
the TFC or TTC determination.
(1.3.1, 1.3.2, 1.3.3)
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure

Guideline 2a:
The proposed VSL is not binary.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R1
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2b:
The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in the
determination of similar penalties for similar violations.

FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSLs are worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications

VRF and VSL Justifications – MOD-001-2, Requirement R2
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The reliability objective is to ensure that a TSP has a written methodology for determining Available
Transfer Capability (ATC) or Available Flowgate Capability (AFC). Although AFC and ATC values influence
Real‐time conditions and have the ability to impact Real‐time operations, these values do not directly
control the reliable operation of the Bulk-Power System. A violation of this requirement would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. As such, a Lower VRF is appropriate.

FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion

Additionally, currently effective Reliability Standards MOD-001-1a, MOD-028-2, MOD-029-1a, and MOD030-2, which are being retired as part of this project, assign VRFs of Lower for requirements related to the
documentation of ATC/AFC methodologies. This proposed Lower VRF is thus consistent with previously
FERC approved requirements.
Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
The Lower VRF is applicable to all parts of the requirement.
Guideline 3- Consistency among Reliability Standards
This requirement is similar to FERC approved MOD-028-2 Requirement R1 and MOD-030-2 Requirement
R1, which deal with TSPs that determine ATC to develop an ATCID and were assigned a VRF of Lower.
MOD-028-2 and MOD-030-2 will be replaced by Requirement R2, and therefore the Lower VRF is
consistent with the previously approved standards.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R2

FERC VRF G4 Discussion

FERC VRF G5 Discussion

FAC-013-2 also contains similar requirements for documenting transfer capability and aligns with the
proposed Lower VRFs in MOD-001-2. There are no other standards addressing this issue.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective, which is that a TSP’s ATC or AFC methodology must be
documented for those registered entities that determine ATC or AFC values and the document is to reflect
current practices. Therefore, the requirement has one VRF that is appropriate for its single obligation.
Proposed VSL

Lower

Moderate

High

Each Transmission Service
Provider that determines AFC
or ATC has not described its
method for accounting for one
of the elements listed in part
2.1 in its written methodology,
provided that element impacts
its AFC or ATC determination.
(2.1)

Each Transmission Service
Provider that determines AFC
or ATC has not described its
method for accounting for two,
three, or four elements listed in
part 2.1 in its written
methodology, provided the
elements impact its AFC or ATC
determination. (2.1)

Each Transmission Service Provider
that determines AFC or ATC has
not described its method for
accounting for five, six, or seven
elements listed in part 2.1 in its
written methodology, provided the
elements impact its AFC or ATC
determination. (2.1)

VRF and VSL Justifications

Severe
Each Transmission Service
Provider that determines AFC or
ATC did not develop an ATCID
describing its AFC or ATC
methodology.
OR

Each Transmission Service
OR
Provider that determines AFC or
ATC did not reflect its current
Each Transmission Service Provider practices for determining AFC or
that uses the Flowgate
ATC values in its ATCID.
Methodology did not use the AFC

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R2
determined by the Transmission
Service Provider for reliabilityrelated constraints identified in
part 1.3. (2.2)

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is not binary.

VRF and VSL Justifications

Guideline 2b:
The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in the
determination of similar penalties for similar violations.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R2
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R3
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The reliability objective is to ensure that a TSP that determines Capacity Benefit Margin (CBM), a
component of ATC/AFC values, documents its methodology for developing its CBM values, which is an
important aspect of the TSP’s ability to communicate to TOPs how its AFC or ATC value was determined.

FERC VRF G1 Discussion
FERC VRF G2 Discussion

FERC VRF G3 Discussion

FERC VRF G4 Discussion

FERC VRF G5 Discussion

VRF and VSL Justifications

As noted above, because ATC/AFC do not directly control the reliable operation of the Bulk-Power System,
a VRF of Lower is appropriate. Furthermore, the proposed Lower VRF is consistent with the FERC approved
MOD-004-1, in which the VRF is Lower for TSPs that maintain CBM.
Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
Requirement R3 does not have any sub-parts or sub-requirements. The Lower VRF is applicable to the
entire requirement.
Guideline 3- Consistency among Reliability Standards
The proposed Lower VRF is consistent with Lower VRF in FERC approved MOD-004-1, which requires TSPs
that maintain CBM to prepare and keep current a CBMID. MOD-004-1 will be retired upon approval of
MOD-001-2. There are no other standards addressing this issue.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R3
The proposed requirement has a single objective, to ensure that a TSP documents its CBM methodology in
an implementation document and ensure the document reflects current practices. Therefore, the
requirement has one VRF for its single obligation.
Proposed VSL
Lower
None.

Moderate
None.

High
None.

Severe
Each Transmission Service
Provider that determines CBM
values did not develop a CBMID
describing its method for
determining CBM values.
OR
Each Transmission Service
Provider that determines CBM
values did not reflect its current
practices for determining CBM
values in its CBMID.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is binary, and therefore, a single severe VSL is necessary.

VRF and VSL Justifications

Guideline 2b:
The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in the
determination of similar penalties for similar violations.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R3
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R4
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The reliability objective is to ensure that TOPs that determine Transmission Reliability Margin (TRM)
values, a component of ATC/AFC, document their methodology for determining the TRM values for use in
the TSP’s determination of AFC and ATC.

FERC VRF G1 Discussion
FERC VRF G2 Discussion

FERC VRF G3 Discussion

FERC VRF G4 Discussion

FERC VRF G5 Discussion

VRF and VSL Justifications

As noted above, because ATC/AFC do not directly control the reliable operation of the Bulk-Power System,
a VRF of Lower is appropriate. Furthermore, the proposed VRF is consistent with the VRF for the FERC
approved version of MOD-008-1, which is Lower for TOPs that maintain TRM.
Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
Requirement R4 contains one VRF for the single obligation for a TOP that determines TRM to document its
methodology to determine TRM.
Guideline 3- Consistency among Reliability Standards
The proposed Lower VRF is consistent with the Lower VRF in FERC approved MOD-008-1, which requires
TOPs that maintain TRM to prepare and keep current a TRMID. MOD-008-1 will be retired upon approval
of MOD-001-2. There are no other standards addressing this issue.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective, to ensure that a TOP documents its TRM methodology in
an implementation document and ensure the document reflects current practices. Therefore, the
requirement has one VRF for its single obligation.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R4
Proposed VSL
Lower
None.

Moderate
None.

High
None.

Severe
Each Transmission Operator that
determines TRM values did not
develop a TRMID describing its
method for determining TRM
values.
OR
Each Transmission Operator that
determines TRM values did not
reflect its current practices for
determining TRM values in its
TRMID.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is binary, and therefore, a single severe VSL is necessary.
Guideline 2b:
The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in the
determination of similar penalties for similar violations.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R4
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications – MOD-001-2, Requirement R5
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The purpose of the requirement is for a TSP or TOP to provide or clarify an element of its TFC or TTC
methodology, ATCID, CBMID, or TRMID, within 45 days of a request. The Lower VRF is appropriate
because the failure for a TOP or TSP to respond to requests on their methodology document(s) in a timely
manner would not put the BES in any immediate risk situation.

FERC VRF G1 Discussion

Guideline 1- Consistency w/ Blackout Report
N/A.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R5
FERC VRF G2 Discussion
FERC VRF G3 Discussion

FERC VRF G4 Discussion

FERC VRF G5 Discussion

Guideline 2- Consistency within a Reliability Standard
The VRF is applicable to all parts of the requirement.
Guideline 3- Consistency among Reliability Standards
This proposed Lower VRF is consistent with the VRF assigned to similar Reliability Standards, including:
FAC-008-3 Requirement R5, which requires TOs or GOs to provide a response to a requesting registered
entity on its Facility Ratings methodology; FAC-010-2.1 Requirement R5, which requires a Planning
Authority to provide a response to an information request to its System Operating Limit (SOL)
methodology; FAC-011-2 Requirement R5, which requires the Reliability Coordinator to provide a
response to an information request of its SOL methodology; and FAC-013-2 Requirements R3 and R5,
which require a Planning Coordinator to provide a response to an information request of its Transfer
Capability methodology or assessment results.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective, which is information sharing on requests for clarification
of a registered entity’s methodologies and determinations of TTC, TFC, ATC, AFC, CBM, or TRM. The
requirement has one VRF for its single obligation.
Proposed VSL

Lower

Moderate

High

Severe

Each Transmission Operator or
Transmission Service Provider
did not respond in writing to a
written request by one or more
of the registered entities

Each Transmission Operator or
Transmission Service Provider
did not respond in writing to a
written request by one or more
of the registered entities

Each Transmission Operator or
Transmission Service Provider did
not respond in writing to a written
request by one or more of the
registered entities specified in

Each Transmission Operator or
Transmission Service Provider
failed to respond in writing to a
written request by one or more of

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R5
specified in Requirement R5
within 45 calendar days from
the date of the request, but did
respond in writing within 75
calendar days.

VRF and VSL Justifications

specified in Requirement R5
within 76 calendar days from
the date of the request, but did
respond in writing within 105
calendar days.

Requirement R5 within 106
calendar days from the date of the
request, but did respond in writing
within 135 calendar days.

the registered entities specified in
Requirement R5.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is not binary.

FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

VRF and VSL Justifications

Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in
the determination of similar penalties for similar violations.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R5
The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications – MOD-001-2, Requirement R6
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The purpose of the requirement is for a registered entity to provide data related to its AFC, ATC, TFC, or
TTC determinations to other entities that need such data for their own determinations. The VRF of Lower
is appropriate because a failure for a TOP or TSP to respond to requests for data on their ATC equation
determinations in a timely manner would not put the BES in any immediate risk situation.

FERC VRF G1 Discussion

Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
The VRF is consistent for all parts of the requirement.
Guideline 3- Consistency among Reliability Standards

FERC VRF G2 Discussion
FERC VRF G3 Discussion

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R6

FERC VRF G4 Discussion

FERC VRF G5 Discussion

This proposed Lower VRF is consistent with VRFs for similar Reliability Standards, including, FAC-013-2
Requirement R6, which requires Planning Coordinator to provide data to support the assessment results
on transfer simulations within 45 calendar days of a request.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective to ensure that TOPs and TSPs share their data related to
ATC/AFC, TTC/TFC, CBM and TRM determinations with other TOPs and TSPs that need such data to
conduct their own determinations.
Proposed VSL

Lower

Moderate

High

Each Transmission Operator or
Transmission Service Provider
did not respond to a written
request for data by one or
more of the registered entities
specified in Requirement R6 by
making the requested data
available within in 45 calendar
days from the date of the
request, but did respond within
75 calendar days.

Each Transmission Operator or
Transmission Service Provider
did not respond to a written
request for data by one or
more of the registered entities
specified in Requirement R6 by
making data available within 76
calendar days from the date of
the request, but did respond
within 105 calendar days.

Each Transmission Operator or
Transmission Service Provider did
not respond to a written request
by one or more of the registered
entities specified in Requirement
R6 by making data available within
106 calendar days from the date of
the request, but did respond
within 135 calendar days.

VRF and VSL Justifications

Severe
Each Transmission Operator or
Transmission Service Provider
failed to respond to a written
request for data by making data
available to one or more of the
entities specified in Requirement
R6.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is not binary.

VRF and VSL Justifications

Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in
the determination of similar penalties for similar violations.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R6
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications

Exhibit G
Summary of Development History and Complete Record of
Development

Summary of Development History
The development record for proposed Reliability Standard MOD-001-2 is summarized
below.
I.

Overview of the Standard Drafting Team
When evaluating a proposed Reliability Standard, the Commission is expected to give

“due weight” to the technical expertise of the ERO.1 The technical expertise of the ERO is
derived from the standard drafting team. For this project, the standard drafting team consisted of
industry experts, all a diverse set of experiences. A roster of the standard drafting team members
is included in Exhibit H.
II.

Standard Development History
A. Standard Authorization Request Development
A Standard Authorization Request (“SAR”) was submitted on July 3, 2013 and accepted

by the Standards Committee (“SC”) on July 11, 2013. A revised version of SAR was posted on
September 25, 2013 in response to industry comment.
B. First Posting- Formal Comment Period and Ballot
Proposed Reliability Standard (MOD A)-MOD-001-2 was posted for a 45-day public
comment period from July 11, 2013 through August 27, 2013. There were 51 sets of comments,
including comments from approximately 160 different people from approximately 106
companies representing all 10 of the industry segments. The proposed Reliability Standard
received a quorum of 76.14% and an approval rating of 51.10%.
The standard drafting team considered stakeholder comments and made the following
changes, among others, to proposed Reliability Standard MOD-001-2 based on those comments:


The language of Requirements R1, R2, R3, and R4 was modified to clarify the
performance expectations. Specifically, the phrase “prepare, keep current and
implement” was removed and replaced by language that more clearly states that the

applicable entity must develop a written methodology or implementation document that
reflects the entity’s current practices for determining ATC/AFC, TTC/TFC, CBM or
TRM.


In response to comments regarding requests for Transmission Operators to account for
reliability-related constraints on neighboring system, the standards drafting team
modified the language in Requirement R1, part 1.3 and Requirement R2, part 2.2 to
clarify what is required.



In response to comments suggesting an exemption for Transmission Operators and
Transmission Service Providers that do not determine TTC/TFC, ATC/AFC, CBM or
TRM, the standard drafting team modified Requirements R1-R4 to clarify that the
requirements only apply to those entities that make such determinations.



The requirement to provide “the rationale for the selection of the TTC or TFC method
being used” was deleted in response to comments that this requirement did not provide
any reliability benefit.



In response to comments that the phrase “projected transmission uses” in Requirement
R1, part 1.1 was unclear, the standard drafting team changed the word “projected” to
“expected”.



The standard drafting team added language in Requirement R2 to reflect the coordination
between Transmission Service Providers that calculate AFC, in response to concerns that
coordination between neighboring Transmission Service Providers would not occur under
the revised version of the Reliability Standard.



The standard drafting team also added to Requirement R2 the language from
Requirement R1 related to accounting for certain system conditions to reflect industry
comment that certain entities do not account for these condition at the TTC/TFC stage but
do so at some point in their methodology for determining ATC/AFC.



The standards drafting team removed the following language from Requirement R3 that
specifically tied CBM to a particular condition: “… to protect system reliability during a
declared NERC Energy Emergency Alert 2 or higher.” NAESB business practice
standards and other established references define and point to the use of CBM. Being
prescriptive in the NERC Reliability Standard would limit NAESB’s ability to further
define the role of CBM and create a conflict if the NERC EEA definitions are changed.



The following language was added to Measure M3 to clarify what evidence is necessary
if the TSP does not maintain a CBM: “if the TSP does not maintain CBM then example
of evidences include but are not limited to; an affidavit, statement, or other document that
states the TSP does not maintain CBM …”



The following language was added to Measure M4 to clarify what evidence is necessary
if the TOP does not maintain TRM: “… for a TOP that does not maintain TRM examples

of evidence include, but are not limited to: an affidavit, statement, or other document
stating that the TOP does not maintain TRM …”


The standard drafting team modified the time for responding to request under
Requirements R5 and R6 from 30 calendar days to 45 calendar days to be consistent with
the timeline provided in Reliability Standards FAC-011 and FAC-013.



A commenter stated that the “subject to confidentiality, regulatory, or security
requirements” language in Requirements R5 and R6 may be unclear. In response, the
SDT added “the data owner’s” before the word “confidentiality”.



In response to comments regarding the types of requests subject to Requirement R6, the
standard drafting team reformatted the requirement to incorporate both single datarequest instances and requests for periodic data.
C. Second Posting- Formal Comment Period and Additional Ballot
Proposed Reliability Standard MOD-001-2 was posted for a second 45-day public

comment period from October 4, 2013 through November 20, 2013. There were 28 set of
responses, including comments from approximately 114 people from approximately 76
companies, representing nine of the 10 industry segments. The proposed Reliability Standard
received a quorum of 81.69% and an approval rating of 82.97%.
The standard drafting team considered stakeholder comments and made the following
changes, among others, to proposed Reliability Standard MOD-001-2 based on those comments:


The standard drafting team deleted the second sentence of the purpose statement to
provide clarity and eliminate redundancy.



To be consistent throughout the standard, the standard drafting team modified the
standard to use the word “determine” when referring to the act by which an entity
calculates, establishes, maintains or determines TTC/TFC, ATC/AFC, CBM or TRM.
The standard drafting team selected “determine” as the best fit to capture both the
situations where a true calculation is performed and others where a limit that was
calculated elsewhere is used.



A commenter noted that in Requirement R1, part 1.3.2 the words “in its methodology”
are missing after the word “describe.” For consistency purposes within the proposed
standard, the language was added.



In response to comments that the measures for Requirements R1 and R2 did not match
the requirements, the standard drafting team modified the measures to more accurately
reflect the requirements.



A commenter suggested changing the word “that” in Requirement R2, part 2.1 to
“provided such elements.” The standard drafting team made the change, which is
consistent with the language in Requirement R1, part 1.2.



Measure 3 was modified to include examples of evidence that entities that do not
determine CBM may provide to demonstrate compliance with the requirement.



For Requirement R6, the language was modified to note that the 45-day response period
is 45 “calendar” days.
D. Final Ballot
Proposed Reliability Standard (MOD A)-MOD-001-2 was posted for a 10-day public

comment period from December 11-20, 2013. The proposed Reliability Standard received a
quorum of 87.16% and an approval rating of 86.40%.
E. Board of Trustees Approval
Proposed Reliability Standard (MOD A)-MOD-001-2 was approved by NERC Board of
Trustees on February 6, 2014.

Complete Record of Development

Program Areas & Departments > Standards > Project 2012-05 ATC Revisions (MOD A)
Project 2012-05 ATC Revisions (MOD A)
Related Files
Status:
A Final ballot for MOD-001-2 concluded at 8 p.m. Eastern on Friday, December 20, 2013. The standard received sufficient affirmative votes for approval and will be
submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory authorities.
Background:
The “MOD A” initiative focuses on address outstanding FERC directives from Order 729 as well as identifying other issues based on operational lessons learned.
The standards involved are:







MOD-001-1a – Available Transmission System Capability
MOD-004-1 – Capacity Benefit Margin
MOD-008-1 – Transmission Reliability Margin Calculation Methodology
MOD-028-1 – Area Interchange Methodology
MOD-029-1a – Rated System Path Methodology
MOD-030-2 – Flowgate Methodology

NERC initiated an informal development process to address directives in Order No. 729 to modify certain aspects of the MOD A standards. Participants were industry
subject matter experts, NERC staff, and staff from FERC’s Office of Electric Regulation. Questions emerged as to whether certain MOD A requirements were
appropriately addressed through NERC Reliability Standards, specifically whether certain MOD A requirements addressed market or competitive issues rather than
reliability issues. The group sought to reorient the MOD A standards to focus on the reliability-related aspects of ATC.
The ad hoc group decided to present a pro forma standard that consolidates the MOD A standards into a single standard covering only the reliability-related impact of
ATC and AFC calculations, such as the need for Transmission Service Providers (TSPs) to implement their ATC calculations in a consistent manner and share ATC data
with neighboring TSPs or other entities who need such data for reliability purposes. The consolidated approach is intended to maintain NERC’s focus on developing and
retaining requirements that support the reliable operation of the Bulk-Power System (BPS).
If you have any questions, please contact [email protected].

Draft

Action

Dates

Results

Consideration of
Comments

MOD-001-2
Clean (39) | Redline to last posting (40)
Implementation Plan (41)
Supporting Materials:

Compliance Input (42)
Final Ballot
SAR
Clean (43) | Redline (44)
Mapping Document (45)

Info>> (50)

Summary>> (51)
12/11/13 - 12/20/13
(closed)

Vote>>

Ballot Results>> (52)

Proposed Timeline for the Formal
Development (46)
Draft Reliability Standard Audit Worksheet
(47)
Consideration of Directives (48)
VRF/VSL Justification (49)
MOD-001-2
Clean (18) | Redline to last posting (19)

Redline to last posting (20)
(REVISED 10/15/13)

Implementation Plan
Clean (21) | Redline to last posting (22)

Supporting Materials:
Unofficial Comment Form (Word) (23)

Additional Ballot and Nonbinding Poll
Updated Info>> (31)

Summary>> (34)

11/08/13 - 11/20/13
Info>> (32)

Ballot Results>> (35)
(extended an additional day tp reach quorum)
(closed)
Non-Binding Poll
Results>> (36)

Vote>>

Comment Period
Info>> (33)

10/04/13 - 11/20/13
(extended an additional day)
(closed)

Submit Comments>>

Comments Received>>
(37)

Consideration of
Comments>> (38)

Compliance Input (24)

SAR
Clean (25) | Redline (26)
Mapping Document (27)

Proposed Timeline for the Formal
Development (28)

Draft Reliability Standard Audit Worksheet
(29)

Consideration of Directives (30)

Draft Standard
MOD-001-2 (1)

MOD-001-2
Ballot and Non-binding Poll
Updated Info>> (10)
Vote>>

Implementation Plan (2)
Standard Authorization Request (3)

Comment Period
Info>> (11)

Supporting Materials:
Unofficial Comment Form (Word) (4)

08/16/13 - 08/27/13
The non-binding poll has been extended an
additional day.
(closed)
Summary>> (13)
07/11/13 - 08/27/13
(closed)

Submit Comments>>

Ballot Results>> (14)
Non-binding Results>>
(15)

Technical White Paper (5)
Mapping Document (6)

07/11/13 - 08/09/13
Join Ballot Pool>>
(closed)

Compliance Input (7)
Proposed Timeline for the Formal
Development (8)

Comments Received>>
(16)
Nomination Period
Info>> (12)

Unofficial Nomination Form (Word) (9)

07/11/13 - 07/22/13
Submit Nomination>>

Consideration of
Comments>> (17)

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed

1. SAR posted for comment on July 11, 2013
Description of Current Draft

This draft standard is concluding informal development and will move to formal development
when authorized by the Standards Committee.

Anticipated Actions

Anticipated Date

SAR Authorized by the Standards Committee

July

45-Day Comment Period Opens

July

Nomination Period Opens

July

Standard Drafting Team Appointed

July

Initial Ballot is Conducted

August

Final Ballot is Conducted

September

Board of Trustees (Board) Adoption

November

Filing to Applicable Regulatory Authorities

December

July 3, 2013

Page 1 of 14

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Effective Dates
1. MOD-001-2 shall become effective the first day of the seventh calendar quarter after
the effective date of the order providing applicable regulatory approval.
2. In those jurisdictions where no regulatory approval is required, MOD-001-2 shall
become effective the first day of the fifth calendar quarter after Board’s approval, or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.

Version History

Version

Date

1

August 26,
2008
November 5,
2009

1a
2

July 3, 2013

TBD

Action

Change Tracking

Adopted by the NERC Board
NERC Board Adopted Interpretation of
R2 and R8
Consolidation of MOD-001-1a, MOD004-1, MOD-008-1, MOD-028-1, MOD029-1a, and MOD-030-2

Interpretation
(Project 2009-15)

Page 2 of 14

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Definitions of Terms Used in the Standard
None.

July 3, 2013

Page 3 of 14

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
When this standard receives ballot approval, the text boxes will be moved to the “Guidelines
and Technical Basis” section of the standard.
A. Introduction

1.

Title:

Available Transmission System Capability

2.

Number:

MOD-001-2

3.

Purpose: (1) To ensure the reliable calculation of Total Flowgate Capability (TFC)
and Total Transfer Capability (TTC) values when those values are used by a
Transmission Service Provider to calculate Available Flowgate Capability (AFC) or
Available Transfer Capability (ATC) or used by a Reliability Coordinator; (2) to require
disclosure of how TFC, TTC, Capacity Benefit Margin (CBM), and Transmission
Reliability Margin (TRM) values are calculated for entities with a reliability need for
the information; and (3) to require the sharing of data with other entities with a
reliability need for the AFC, ATC, TFC, TTC, CBM, or TRM values.

4.

Applicability:
4.1. Functional Entity
4.1.1 Transmission Operator
4.1.2 Transmission Service Provider
4.2. Exemptions: The following is exempt from MOD-001-2.
4.2.1 Functional Entities operating within ERCOT

July 3, 2013

Page 4 of 14

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
B. Requirements and Measures

Rationale for R1: TFC and TTC values are important to the reliability of the bulk power system when they
are used to determine AFC and ATC or in the real-time operation of the transmission system. The
Transmission Operator needs to calculate a value that protects reliability both on its system and
neighboring systems. Having a current and accurate description of this process allows neighboring systems
and their Transmission Service Provider to understand how the values were determined. In addition, if a
Transmission Operator’s method by default does not monitor one or more constraints on another
Transmission Operator’s system, then they should describe how they are monitoring those constraints
when requested to by that affected Transmission Operator. Those off-system constraints should be
monitored at a Power Transfer Distribution Factor (PTDF) or Outage Transfer Distribution Factor (OTDF) of
five percent or less, if appropriate to the means of determining TFC or TTC.

R1.

Each Transmission Operator shall prepare, keep current, and implement a TFC or TTC methodology
for calculating its TFC or TTC, if: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

1.1.

1.2.



Used by that Transmission Operator;



Requested by its Transmission Service Provider(s); or



Requested by its Reliability Coordinator.

The methodologies shall include:


A statement that the TTC or TFC shall incorporate facility ratings, voltage limits, and stability
limits pre- and post-contingency;



A description of how this is accomplished;



What criteria (if any) is used to select which of the limits, or System Operating Limits (SOLs),
are relevant to the calculation; and



The rationale for the selection of the TTC or TFC method being used.

The methodologies shall address, at a minimum, the following elements of the TFC or TTC
calculation:


How simulation of transfers are performed through the adjustment of generation, Load, or
both;



Transmission topology, including, but not limited to, additions and retirements;



Currently approved and projected transmission uses;



Planned outages;



Parallel path (loop flow) adjustments;



Load forecast; and



Generator dispatch, including, but not limited to, additions and retirements.

July 3, 2013

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
1.3.

The methodologies shall include any reliability-related constraints that are requested to be
included by another Transmission Operator, provided the constraints are also used in that
Transmission Operator’s TFC or TTC calculation.
1.3.1 The Transmission Operator shall use a distribution factor (Power Transfer Distribution
Factor (PTDF) or Outage Transfer Distribution Factor (OTDF)) of five percent or less when
determining if these constraints should be monitored.

1.4.

The methodologies shall address the periodicity for the Transmission Operator to provide
updated TFC or TTC values to the Transmission Service Provider.

M1. Examples of evidence include, but are not limited to:


A dated effective methodology that is posted on the Transmission Operator's website, or
their Transmission Service Provider’s website, or on the Open Access Same-Time Information
System (OASIS);



Descriptions within the methodology regarding how constraints identified by another
Transmission Operator are included and how a distribution factor is applied, or a statement
that such a request has not been made, or the TTC or TFC calculation does not use PTDF or
OTDF in the calculation; or



Language in the TFC or TTC methodology that specifies the periodicity of providing updated
TFC or TTC values to the Transmission Service Provider and evidence that the updated values
were provided according to the specified timeframes.

If the Transmission Operator and Transmission Service Provider are the same entity then evidence of
providing the values can be established by a statement that they are the same entity.
Rationale for R2:
ATC is a prediction of the remaining amount of power that can be transferred on a path between two
systems for defined system conditions. AFC is a prediction of the amount of additional power for defined
system conditions that could flow over a particular flowgate, which may involve one or more paths
between systems. The ATC or AFC value influences, to varying degrees depending on the locality, the
system conditions that the operator inherits in real time, which gives the Transmission Operator and
others an interest in understanding how the values are calculated. To ensure that the Transmission
Operator and others have this information, the Transmission Service Provider must have an Available
Transfer Capability Implementation Document (ATCID) that accurately describes the current process of
determining this value.

R2.

Each Transmission Service Provider shall prepare, keep current, and implement an Available
Transfer Capability Implementation Document (ATCID) that describes the methodology used to
calculate ATC or AFC values. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

July 3, 2013

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
M2. Examples of evidence include, but are not limited to, a dated effective ATCID that is posted on the
Transmission Service Provider’s website or OASIS and a demonstration that select currently active
values of ATC were calculated based on the current ATCID.
Rationale for R3:
Capacity Benefit Margin (CBM) is a value used by a Transmission Service Provider when determining ATC.
To ensure transparency and reliability, the Transmission Service Provider must have a Capacity Benefit
Margin Implementation Document (CBMID) that accurately describes the current process of determining
this value that can be shared with other entities with a reliability need to understand the Transmission
Service Provider’s process for creating the CBM value. When a Transmission Service Provider does not use
CBM, the value in the ATC calculation is zero.
The CBM value could have been included in the ATCID. However, Transmission Service Providers have
other obligations (tariffs, contracts, future NAESB standards) that reference the CBMID; keeping it as its
own document seemed to be less burdensome then requiring its inclusion in the ATCID.

R3.

Each Transmission Service Provider shall prepare, keep current, and implement a Capacity Benefit
Margin Implementation Document (CBMID) that describes its method for establishing margins to
protect system reliability during a declared NERC Energy Emergency Alert 2 or higher.
Transmission Service Providers that do not use Capacity Benefit Margin (CBM) shall state this in
the CBMID. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

M3. Examples of evidence include, but are not limited to, a dated effective CBMID that is posted on the
Transmission Service Provider’s website or OASIS and a demonstration, such as a study report,
that select currently active values of CBM were determined per the CBMID, if the Transmission
Service Providers uses CBM.

Rationale for R4:
Transmission Reliability Margin (TRM) is additional capacity held by a Transmission Service Provider when
determining ATC and providing additional operating margin to a Transmission Operator. To ensure
transparency and reliability, the Transmission Operator must have a Transmission Reliability Margin
Implementation Document (TRMID) that accurately describes their current process of determining this
value and can be shared with entities that have a reliability need to understand the Transmission
Operator’s process for creating the TRM value. When a Transmission Service Provider does not utilize TRM,
the value in the ATC calculation is zero.
The TRM value could have been included in the ATCID. However, there are other obligations upon a
Transmission Service Provider (tariffs, contracts, future NAESB standards) that reference the TRMID, so
keeping it as its own document seemed to be less burdensome then requiring its inclusion in the ATCID.

July 3, 2013

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
R4.

Each Transmission Operator shall prepare, keep current, and implement a Transmission Reliability
Margin Implementation Document (TRMID) that describes its method for establishing margins to
protect system reliability.
Transmission Operators that do not use Transmission Reliability Margin (TRM) shall state this in
the TRMID. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

M4. Examples of evidence include, but are not limited to, a dated effective TRMID that is posted on the
Transmission Operator’s website or OASIS and a demonstration, such as a study report, that select
currently active values of TRM were determined per the TRMID, if the Transmission Operator uses
TRM.
Rationale for R5:
One of this standard’s primary goals is transparency in the methods used to determine ATC or AFC. To
support that goal, this requirement requires the Transmission Service Provider and Transmission Operator
to share their implementation document (if not already posted publicly) and respond to questions when
asked in writing to do so under the standard. This requirement establishes a threshold for a question to fall
under the requirement, so that routine and customary discussions do not need to be documented.

R5.

Within 30 calendar days of receiving a written request that references this requirement from a
Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission Planner,
Transmission Service Provider, or any other registered entity that demonstrates a reliability need,
each Transmission Service Provider and Transmission Operator (subject to confidentiality,
regulatory, or security requirements) shall provide: [Violation Risk Factor: Lower] [Time Horizon:
Operations Planning]
5.1.

A written response to any request for clarification of its ATC or AFC methodology.

5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s
effective:

5.3.

5.2.1.

CBMID; and

5.2.2.

TFC or TTC methodology.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s
effective:
5.3.1.

ATCID; and

5.3.2.

TRMID.

M5. Examples of evidence include, but are not limited to, dated records of the request from a Planning
Coordinator, Reliability Coordinator, Transmission Operator, Transmission Planner, Transmission
Service Provider, or another registered entity who demonstrates a reliability need; the

July 3, 2013

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Transmission Service Provider’s response to the request; and a statement by the Transmission
Service Provider that they have received no requests.
Rationale for R6:
A Transmission Service Provider or Transmission Operator may need data (e.g., load forecast, expected
dispatch, planned outages) from its neighbor in order to accurately calculate TTC, TFC, ATC, or AFC values.
This requirement allows them to pursue accessing that data with the limitation that the owner of the data
is not obligated to modify it for another entity’s use, nor provide data that is otherwise accessible. This
requirement should not discourage data exchanges and data requests, especially those already in place.
Therefore, the requirement is specific in that it is invoked only when specifically invoked by the requestor
and assumes that there may have been other attempts to get the data that were unsuccessful.

R6.

Within 30 days of a written request that references this requirement from another Transmission
Service Provider or Transmission Operator, a Transmission Service Provider or Transmission
Operator shall share data used in their respective AFC, ATC, TFC, or TTC calculations (subject to
confidentiality, regulatory, or security requirements). [Violation Risk Factor: Lower] [Time Horizon:
Operations Planning]
6.1.

To be valid, the request must specify that the data is for use in the requesting party’s AFC,
ATC, TFC, or TTC calculations.

6.2.

The Transmission Service Provider and Transmission Operator are not required to modify
the data from the format in which they maintain, use, or currently make available the
data.

M6. Examples of evidence include, but are not limited to:


Dated records of a registered entity’s request, and the Transmission Service Provider’s or
Transmission Operator’s response to the request;



A statement from the requestor that the request was met; or



A statement by the Transmission Service Provider or Transmission Operator that they have
received no requests under this requirement.

In the case of a data request that involves the providing of data on regular intervals, examples of
evidence include, but are not limited to:

July 3, 2013



Dated records of the registered entity’s request;



Examples of the Transmission Service Provider or Transmission Operator providing the data
at intervals; or



A statement from the requestor that the request is being met.

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
C. Compliance

1.

Compliance Monitoring Process:
1.1. Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” refers to NERC or the Regional
Entity in their respective roles of monitoring and enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention:
The following evidence retention periods identify the period of time an entity is required to retain specific evidence to
demonstrate compliance. For instances in which the evidence retention period specified below is shorter than the
time since the last audit, the Compliance Enforcement Authority may ask the entity to provide other evidence to
show that it was compliant for the full time period since the last audit.


Implementation and methodology documents shall be retained for five years.



Calculations and other components of implementation and methodology documents shall be retained to show
compliance in calculating:
o Hourly values for the most recent 14 days;
o Daily values for the most recent 30 days; and
o Monthly values for the most recent 60 days.



If a responsible entity is found non-compliant, it shall keep information related to the non-compliance until
mitigation is complete and approved.



The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted
subsequent audit records.

1.3. Compliance Monitoring and Assessment Processes:


As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment Processes” refers to the
identification of the processes that will be used to evaluate data or information for the purpose of assessing
performance or outcomes with the associated reliability standard.

1.4. Additional Compliance Information:

July 3, 2013

Page 10 of 14

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability


None

D. Regional Variances

None.
E. Interpretations

None.
F. Associated Documents

None.
Table of Compliance Elements
R#

Time
Horizon

VRF

R1

Operations
Planning

Lower

R2

Operations
Planning

Lower

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

The Transmission Operator
prepared, kept current, and
implemented a
methodology that is used
by its Transmission Service
Provider, but does not
address one of the
requirement parts.
None.

The Transmission Operator
prepared, kept current, and
implemented a
methodology that is used
by its Transmission Service
Provider, but does not
address two of the
requirement parts.
None.

The Transmission Operator
prepared, kept current, and
implemented a
methodology that is used
by its Transmission Service
Provider, but does not
address three of the
requirement parts.
None.

The Transmission Operator
did not prepare, keep
current, or implement a
methodology.

The Transmission Service
Provider has not prepared
an ATCID.
OR
The Transmission Service
Provider has not kept
current an ATCID.

July 3, 2013

Page 11 of 14

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL
OR

R3

Operations
Planning

Lower

None.

None.

None.

The Transmission Service
Provider has not
implemented an ATCID.
The Transmission Service
Provider has not prepared
a CBMID.
OR
The Transmission Service
Provider has not kept
current a CBMID.
OR

R4

Operations
Planning

Lower

None.

None.

None.

The Transmission Service
Provider has not
implemented a CBMID.
The Transmission Operator
has not prepared a TRMID.
OR
The Transmission Operator
has not kept current a
TRMID.
OR
The Transmission Operator
has not implemented a

July 3, 2013

Page 12 of 14

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL
TRMID.

R5

Operations
Planning

Lower

R6

Operations
Planning

Lower

July 3, 2013

The responsible entity
responds to a written
request by one or more of
the entities specified in
requirement R5 in 31 or
more calendar days, but
not more than 60 calendar
days after the request.

The responsible entity
responds to a written
request by one or more of
the entities specified in
requirement R5 in 61 or
more calendar days, but
not more than 90 calendar
days after the request.

The responsible entity
responds to a written
request by one or more of
the entities specified in
requirement R6 to share
data used in their TTC or
ATC calculation in 31 or
more calendar days, but
not more than 60 calendar
days after the request.

The responsible entity
responds to a written
request by one or more of
the entities specified in
requirement R6 to share
data used in their TTC or
ATC calculation in 61 or
more calendar days, but
not more than 90 calendar
days after the request.

The responsible entity
responds to a written
request by one or more of
the entities specified in
requirement R5 in 91 or
more calendar days, but
not more than 120
calendar days after the
request.
The responsible entity
responds to a written
request by one or more of
the entities specified in
requirement R6 to share
data used in their TTC or
ATC calculation in 91 or
more calendar days, but
not more than 120
calendar days after the
request.

The responsible entity fails
to respond to a written
request by one or more of
the entities specified in
requirement R5.

The responsible entity fails
to respond to a written
request by one or more of
the entities specified in
requirement R6.

Page 13 of 14

Application Guidelines
Guidelines and Technical Basis
Please see the MOD A White Paper for further information regarding the technical basis for
each requirement.

July 3, 2013

Page 14 of 14

Implementation Plan
Project 2012-05 MOD A
Implementation Plan for MOD-001-2 – Available Transmission System Capability
Approvals Required
MOD-001-2 – Available Transmission System Capability
Prerequisite Approvals
There are no other standards that must receive approval prior to the approval of this standard.
Revisions to Glossary Terms
None
Applicable Entities
Transmission Operator
Transmission Service Provider
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
MOD-001-2 shall become effective as follows:
1. MOD-001-2 shall become effective the first day of the seventh calendar quarter after the
effective date of the order providing applicable regulatory approval.
2. In those jurisdictions where no regulatory approval is required, MOD-001-2 shall become
effective the first day of the fifth calendar quarter Board of Trustees’ approval, or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities.
Justification
NERC is working with the North American Energy Standards Board (NAESB) to transition those
elements of the existing standards that relate to commercial or business practices and will not be

retained in MOD-001-2 from the NERC Reliability Standards to NAESB’s business practice standards.
The 18-month implementation period will provide sufficient time for NAESB, working through its
business practice development process, to adopt standards that address the requirements proposed
for retirement. NERC expects that following Board of Trustee approval of the proposed standard,
NERC will submit a request to NAESB to adopt the standards proposed or retirement into their
commercial and business practice standards and to consider the commission directives associated with
those standards. NERC expects that in adopting the standards to be retired, NAESB will provide for an
effective date that will coincide with the effective date proposed in MOD-001-2.
Retirements
MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and MOD-030-2 shall be retired
upon MOD-001-2 becoming effective.

Project 2012-05 ATC Revisions Implementation Plan
July 3, 2013

2

Standards Authorization Request Form
When completed, please email this form to:

[email protected]

NERC welcomes suggestions to improve the
reliability of the bulk power system through
improved reliability standards. Please use this form
to submit your request to propose a new or a
revision to a NERC’s Reliability Standard.

Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard:

Available Transmission System Capability

Date Submitted:

July 3, 2013

SAR Requester Information
Name:

Ryan Stewart

Organization:

NERC

Telephone:

404-446-2569

E-mail:

[email protected]

SAR Type (Check as many as applicable)
New Standard

Withdrawal of existing Standard

Revision to existing Standard

Urgent Action

SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
Resolve FERC directives, incorporate lessons learned, update standards, and to incorporate initiatives
such as results-based, performance-based, Paragraph 81, etc.
Purpose or Goal (How does this request propose to address the problem described above?):
The pro forma standard consolidates the reliability components of the existing standards and retires
market-based requirements.

Standards Authorization Request Form

SAR Information
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
The objectives are to address the outstanding directives from FERC Order 729, remove market-based
requirements from the requirements, and incorporate lessons learned.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
An informal development ad hoc group is presenting a pro forma standard that consolidates the existing
MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and MOD-030-2 into a single
standard that covers the reliability-related impact of Available Transfer Capability (ATC) and Available
Flowgate Capability (AFC) calculations, such as the need for Transmission Service Providers to
implement their ATC or AFC calculations in a consistent manner and share ATC or AFC data with their
neighboring Transmission Service Providers or other entities who need such data for reliability
purposes.
The pro forma standard requirements are placed within a new version of MOD-001 (MOD-001-2).
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
Detailed description of this project can be found in the Technical White Paper of this SAR submittal
package.

Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization

Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing Authority

Integrates resource plans ahead of time, and maintains load-

Project 2012-05 Standards Authorization Request
July 3, 2013

2

Standards Authorization Request Form

Reliability Functions
interchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.
Interchange Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.

Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.

Transmission Service
Provider

Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).

Transmission Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling
Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market Operator

Interface point for reliability functions with commercial functions.

Load-Serving Entity

Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.

Reliability and Market Interface Principles

Project 2012-05 Standards Authorization Request
July 3, 2013

3

Standards Authorization Request Form

Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
Yes
Yes
Yes

Yes

Related Standards
Standard No.
MOD-001-1a

Explanation
Available Transmission System Capability

Project 2012-05 Standards Authorization Request
July 3, 2013

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Standards Authorization Request Form

Related Standards
MOD-004-1

Capacity Benefit Margin

MOD-008-1

Transmission Reliability Margin Calculation Methodology

MOD-028-1

Area Interchange Methodology

MOD-029-1a

Rated System Path Methodology

MOD-030-2

Flowgate Methodology

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

ERCOT

FERC Order 729 states, in Paragraph 298, “…it is appropriate to exempt entities within ERCOT
from complying with these Reliability Standards. We agree that, due to physical differences of
ERCOT’s transmission system, the MOD Reliability Standards approved herein would not
provide any reliability benefit within ERCOT.”

FRCC

None

MRO

None

Project 2012-05 Standards Authorization Request
July 3, 2013

5

Standards Authorization Request Form

Regional Variances
NPCC

None

RFC

None

SERC

None

SPP

None

WECC

None

Project 2012-05 Standards Authorization Request
July 3, 2013

6

Unofficial Comment Form
Project 2012-05 ATC Revisions
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the draft MOD-001-2 standard. The electronic comment form must be completed by 8:00
p.m. ET on Monday, August 26, 2013.
If you have questions please contact Ryan Stewart via email or by telephone at 404-446-2569.
The project page may be accessed by clicking here.
Background Information

On November 24, 2009, FERC issued Order No. 729, Mandatory Reliability Standards for the Calculation of
Available Transfer Capability, Capacity Benefit Margins, Transmission Reliability Margins, Total Transfer
Capability, and Existing Transmission Commitments and Mandatory Reliability Standards for the BulkPower System. From this Order there are 20 outstanding directives, which are explained in detail in the
technical white paper (see project page).
The informal consensus building for MOD A began in February 2013. Specifically, the ad hoc group
engaged stakeholders on how best to address the FERC directives, paragraph 81 candidates, and resultsbased approaches. A discussion of the ad hoc group’s consensus building and collaborative activities are
included in the technical white paper.
Based on stakeholder outreach, the MOD A ad hoc group has developed one revised reliability standard
that addresses the FERC directives, paragraph 81 candidates, and making the requirements more resultsbased while consolidating the MOD A standards (MOD-001, MOD-004, MOD-008, MOD-028, MOD-029,
and MOD-030) into a single standard covering the reliability-related impact of ATC and AFC calculations.
This posting is soliciting comment on a pro forma standard and a Standard Authorization Request (SAR).
You do not have to answer all questions. Enter comments in simple text format. Bullets, numbers, and
special formatting will not be retained.

Question

1. Do you have any specific questions or comments relating to the scope of the proposed standard action
or any component of the SAR outside of the pro forma standard?
Yes
No
Comments:
2. Are there any specific elements from the original MOD-001, MOD-004, MOD-008, MOD-028, MOD029, or MOD-030 that you believe are critical to reliability that have not been retained? Please explain.
Yes
No
Comments:
3. Please specify if you have comments or proposed changes to any of the Requirements of the pro forma
standard.
Comments:

Unofficial Comment Form
Project 2012-05 ATC Revisions | July 2013

2

White Paper on
the MOD A
Standards
MOD-001, MOD-004, MOD-008,
MOD-028, MOD-029, and MOD-030
July 3, 2013

NERC | MOD A White Paper | July 3, 2013
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3353 Peachtree Road NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Table of Contents
Table of Contents ......................................................................................................................................................................... 2
Executive Summary ..................................................................................................................................................................... 5
Purpose ........................................................................................................................................................................................ 6
History of the MOD A Informal Development ............................................................................................................................. 7
Ad Hoc Group Meetings........................................................................................................................................................... 7
Other Outreach ........................................................................................................................................................................ 7
Technical Discussion on Various Existing Methods ..................................................................................................................... 8
General Description of ATC Methods ...................................................................................................................................... 8
DETERMINATION OF ATC ..................................................................................................................................................... 8
DETERMINATION OF ETC ..................................................................................................................................................... 9
DETERMINATION OF CBM ................................................................................................................................................... 9
DETERMINATION OF TRM .................................................................................................................................................. 10
Area Interchange Method – MOD-028 .................................................................................................................................. 12
PROCEDURE FOR CALCULATING AREA INTERCHANGE METHOD ...................................................................................... 12
TRANSLATION OF SYSTEM IMPACTS TO TTC ..................................................................................................................... 12
ATC TIME VARIATION AND NETWORK DEPENDENCY ........................................................................................................ 13
ADDITIONAL COMMENTS ON DETERMINATION ON AREA INTERCHANGE METHOD OF TTC ........................................... 13
Rated System Path Method – MOD-029................................................................................................................................ 13
OVERVIEW ......................................................................................................................................................................... 13
UNSCHEDULED FLOW OR PARALLEL PATH FLOW .............................................................................................................. 14
CAPACITY ALLOCATION ...................................................................................................................................................... 14
ATC CALCULATION APPROACH .......................................................................................................................................... 14
EXAMPLE OF ATC DETERMINATION................................................................................................................................... 15
Flowgate Method – MOD-030 ............................................................................................................................................... 17
PROCEDURE FOR CALCULATING FLOWGATE METHOD ..................................................................................................... 17
Flowgate Criteria ................................................................................................................................................................ 18
ATC Calculation Example ................................................................................................................................................... 18
Other Technical Discussions ...................................................................................................................................................... 20
Respecting and Utilizing Neighboring Systems Data ............................................................................................................. 20
Operating the System ............................................................................................................................................................ 20
Oversold Conditions............................................................................................................................................................... 20
Conclusion for Revising the Standards .................................................................................................................................. 21
Proposed Resolution .................................................................................................................................................................. 22
Role of the Existing Standards ............................................................................................................................................... 22
Transition Considerations Created by Consolidation of the Existing Standards .................................................................... 22
Purpose and Placement of the Pro Forma Standard ............................................................................................................. 23
Calculation of Total Transfer Capability and Total Flowgate Capability – Addressed in Requirement R1 of Pro Forma
Standard................................................................................................................................................................................. 23
Calculation of Available Transfer Capability and Available Flowgate Capability - Addressed in Requirement R2 of Pro
Forma Standard ..................................................................................................................................................................... 23

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Calculation of Transmission Reliability Margin and Capacity Benefit Margin - Addressed in Requirements R3 & R4 of Pro
Forma Standard ..................................................................................................................................................................... 24
Sharing Data - Addressed in Requirements R5 & R6 of Pro Forma Standard ........................................................................ 24
Jurisdictional vs. Non-jurisdictional Discussion ..................................................................................................................... 24
Feedback from NERC Compliance.......................................................................................................................................... 24
Outstanding FERC Directives ..................................................................................................................................................... 25
S-Ref 10204 ............................................................................................................................................................................ 25
Consideration of Directive ................................................................................................................................................. 25
S-Ref 10206 ............................................................................................................................................................................ 25
Consideration of Directive ................................................................................................................................................. 25
S-Ref 10207 ............................................................................................................................................................................ 26
Consideration of Directive ................................................................................................................................................. 26
S-Ref 10208 ............................................................................................................................................................................ 26
Consideration of Directive ................................................................................................................................................. 26
S-Ref 10209 ............................................................................................................................................................................ 27
Consideration of Directive ................................................................................................................................................. 27
S-Ref 10211 ............................................................................................................................................................................ 27
Consideration of Directive ................................................................................................................................................. 27
S-Ref 10212 ............................................................................................................................................................................ 27
Consideration of Directive ................................................................................................................................................. 27
S-Ref 10214 ............................................................................................................................................................................ 28
Consideration of Directive ................................................................................................................................................. 28
S-Ref 10215 ............................................................................................................................................................................ 28
Consideration of Directive ................................................................................................................................................. 28
S-Ref 10216 ............................................................................................................................................................................ 29
Consideration of Directive ................................................................................................................................................. 29
S-Ref 10217 ............................................................................................................................................................................ 29
Consideration of Directive ................................................................................................................................................. 29
S-Ref 10218 ............................................................................................................................................................................ 30
Consideration of Directive ................................................................................................................................................. 30
S-Ref 10219 ............................................................................................................................................................................ 30
Consideration of Directive ................................................................................................................................................. 30
S-Ref 10220 ............................................................................................................................................................................ 30
Consideration of Directive ................................................................................................................................................. 30
S-Ref 10221 ............................................................................................................................................................................ 31
Consideration of Directive ................................................................................................................................................. 31
S-Ref 10222 ............................................................................................................................................................................ 31
Consideration of Directive ................................................................................................................................................. 31
S-Ref 10223 ............................................................................................................................................................................ 31
Consideration of Directive ................................................................................................................................................. 31

NERC | MOD A White Paper | July 3, 2013
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S-Ref 10226 ............................................................................................................................................................................ 32
Consideration of Directive ................................................................................................................................................. 32
S-Ref 10227 ............................................................................................................................................................................ 32
Consideration of Directive ................................................................................................................................................. 32
S-Ref 10229 ............................................................................................................................................................................ 32
Consideration of Directive ................................................................................................................................................. 32
Conclusion ................................................................................................................................................................................. 33
Appendix A: Acronyms ............................................................................................................................................................... 34
Appendix B: Entity Participants ................................................................................................................................................. 35

NERC | MOD A White Paper | July 3, 2013
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Executive Summary
NERC Reliability Standards MOD-001, -004, -008, -028, -029, and -030 (referred to herein as the “MOD A” standards), were
established in response to the Federal Energy Regulatory Commission’s (“FERC” or “Commission”) Orders No. 890 and 693
and were approved in Order No. 729. Collectively, the MOD A standards pertain to methodologies for the consistent and
transparent calculation of Available Transfer Capability (ATC) or Available Flowgate Capability (AFC) as follows:
•
•
•
•
•
•

MOD-001-1a is the umbrella standard that contains the generic requirements applicable to all methods of
determining ATC.
MOD-004-1 provides for the consistent calculation, verification, preservation, and use of Capacity Benefit Margin
(CBM).
MOD-008-1 provides for the consistent calculation, verification, preservation, and use of Transmission Reliability
Margin (TRM).
MOD-028-1 provides for the development and documentation of transfer capability calculations for registered
entities using the Area Interchange Methodology.
MOD-029-1a provides for the development and documentation of transfer capability calculations for registered
entities using the Rated System Path (RSP) Methodology.
MOD-030-2 provides for the development and documentation of transfer capability calculations for registered
entities using the Flowgate Methodology.

NERC initiated an informal development process to address directives in Order No. 729 to modify certain aspects of the
MOD A standards. Participants were industry subject matter experts, NERC staff, and staff from FERC’s Office of Electric
Regulation. Questions emerged as to whether certain MOD A requirements were appropriately addressed through NERC
Reliability Standards, specifically whether certain MOD A requirements addressed market or competitive issues rather than
reliability issues. The group sought to reorient the MOD A standards to focus on the reliability-related aspects of ATC.
The ad hoc group decided to present a pro forma standard that consolidates the MOD A standards into a single standard
covering only the reliability-related impact of ATC and AFC calculations, such as the need for Transmission Service Providers
(TSPs) to implement their ATC calculations in a consistent manner and share ATC data with neighboring TSPs or other
entities who need such data for reliability purposes. The consolidated approach is intended to maintain NERC’s focus on
developing and retaining requirements that support the reliable operation of the bulk power system (BPS).
The pro forma standard covers the Total Flowgate Capability (TFC) Total Transfer Capability (TTC) and methods and what
must be included within them. It also calls for each TSP to prepare, keep current, and implement an Available Transmission
Capability Implementation Document (ATCID) that describes its method for calculating ATC or AFC values. The pro forma
standard calls for each TSP to prepare, keep current, and implement a Capacity Benefit Margin Implementation Document
(CBMID) that describes its method for establishing margins to protect system reliability during a declared Energy Emergency
Alert 2 (EEA 2) or higher. Further, it calls for each Transmission Operator (TOP) to prepare, keep current, and implement a
Transmission Reliability Margin Implementation Document (TRMID) that describes its method for establishing margins to
protect system reliability. The three requirements are not overly prescriptive, regardless of which method the entity uses to
calculate available transmission system capability. This follows the approach of consolidating the existing standards into
one pro forma standard. Lastly, the pro forma standard covers information and data sharing requirements for registered
entities that demonstrate a reliability need. The two information and data sharing requirements call for what makes a
request valid, the time an entity has to respond to a valid request, and other language to address confidentiality concerns.
The ad hoc group recognizes, however, that even if certain MOD A requirements do not address reliability issues and would
not be included in the pro forma standard, those requirements may be essential for market or competition purposes and
could be transitioned to an organization other than the Electric Reliability Organization (ERO), such as the North American
Energy Standards Board (NAESB), that focuses on market-based standards. The implementation plan for the consolidated
standard will cover such a transition.
As detailed below, the MOD A informal ad hoc group discussed each of the outstanding directives from FERC Order No. 729
to determine which directives continued to apply to the consolidated reliability standard and need to be addressed therein,
and which was applicable to a market-based element of the current standard and would be more appropriately addressed
by the organization that would eventually take over these standards.
NERC | MOD A White Paper | July 3, 2013
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Purpose
The purpose of this white paper is to provide background and technical rationale for the proposed revisions to the group of
approved MOD standards that have a common mission of delineating rules around information on the transparency of bulk
energy transfers and transmission availability.
This document outlines the next generation of these standards and proposes to combine the reliability components in this
package of standards into one standard. The remaining requirements in this package would either be retired as
administrative, captured as instructional or explanatory in a white paper, or could be transferred from the NERC Reliability
Standards to another regulatory standards body, such as NAESB. This is appropriate as requirements with a commercial or
business focus are not within the ERO’s jurisdiction and are better aligned for long-term maintenance outside of the NERC
Reliability Standards and reduce the NERC standard to the core reliability concepts regarding TTC, TFC, ATC, AFC, CBM, and
TRM.
This white paper lays out a common understanding of industry perspectives on topics included in these standards. It further
provides an explanation of how each of the outstanding FERC directives assigned to these FERC approved standards are
being addressed by NERC and suggests how they could be addressed if they are owned by NAESB or another regulatory
standards body. This paper will also provide technical justifications and support for the proposed requirements that are
retained and placed into the pro forma standard. The contents of this paper are intended to assist the standard drafting
team assigned to MOD A and industry stakeholder participants with background information to move this standard package
along in the formal development process. Eventually, following industry and the NERC Board of Trustees’ adoption of the
proposed standard, this white paper will be used to support the filing to the applicable regulatory authorities.

NERC | MOD A White Paper | July 3, 2013
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History of the MOD A Informal Development
Ad Hoc Group Meetings
The first informal meeting of the MOD A informal development process was held February 12–14, 2013, at NERC’s
Washington, D.C. office. At that meeting, a small ad hoc group of industry subject matter experts (SMEs) and a FERC
participant discussed the 20 outstanding FERC directives and possible resolutions to address the directives. The group
members also discussed operational lessons learned since June 18, 2007. It was clear that smaller subgroups would need to
focus specifically on MOD-028, MOD-029, or MOD-030, based on the methodology that was chosen in MOD-001 for
calculating available transmission system capability.
The ad hoc group met again March 12–14, 2013, at NERC’s Atlanta office. Members continued efforts from the first
meeting, several new participants attended. A third informal meeting was held April 16–18, 2013, and the conversation
focused on beginning the development of materials for submittal of the Standard Authorization Request (SAR) to the NERC
Standards Committee (SC). The MOD A group met again June 4–6, 2013, at Bonneville Power Administration’s office in
Portland, Oregon to finalize the materials for submittal to the SC.
Additional meetings occurred with specific subgroups. The MOD-028 subgroup met at Orlando Utilities Commission in
Orlando, Florida on March 5 for a one-day working session. The subgroup went through each of the requirements and
identified the rationale of the requirement, the FERC directives associated with the standard, the issues associated with the
requirement, and possible considerations for resolutions. A MOD-030 subgroup meeting was also held at PJM
Interconnection’s offices in Valley Forge, Pennsylvania on March 22, 2013 to examine MOD-030 in a similar approach. The
MOD-029 subgroup met at Idaho Power in Boise, Idaho on April 11, 2013.
Industry opinions regarding reliability requirements vs. market requirements and how the two should be separated
surfaced via the consensus-building approach used during this informal development process. The group went through
MOD-001, MOD-004, MOD-008, MOD-028, MOD-029, and MOD-030 and discussed that most of the requirements are
market-based and do not belong in the NERC Reliability Standards. Discussions on this matter are described in detail later in
this paper.

Other Outreach
Informal development for MOD A yielded different opportunities for outreach to industry at large. There were numerous
working groups, task forces, NERC Board standing committees, compliance forums, and other workshops. NERC staff and
various MOD A participants presented at multiple junctures during the informal development period to keep industry
participants updated regarding the progress the MOD A ad hoc group was making.
Furthermore, various representatives participated in various levels of involvement throughout the informal development
for the MOD A initiative. A list of entities were reached out to during the MOD A initiative are found in Appendix B.

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Technical Discussion on Various Existing Methods
This section focuses on the technical aspects of the methods for calculating available transmission system capability. It was
important for the MOD A informal ad hoc group to have users of the Area Interchange, Rated System Path, and Flowgate
methods all come to a common ground to meet the group’s objective to consolidate the existing standards into one.
Therefore, the group discussed each of the existing methods at length and developed this section of the white paper, which
walks through the three methods of determining TTC, TFC, ATC, and AFC at a high level.

General Description of ATC Methods
This section contains a description of ATC or AFC methods that apply to each of the three methods for calculating ATC
described in the existing MOD A standards. The general description and criteria of the methods for calculating ATC and AFC
are based on:
•

Documents from the previous MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1, and MOD-030-2
standards

•

The NERC document Available Transfer Capability Definitions and Determination

•

The NERC document Transmission Capability Margins and Their Use in ATC Determination

•

Decades of experience by various TOPs and TSPs participating in the ad hoc group

1
2

This paper provides a high level discussion of common understandings, practices and common language around this subject
for the purpose of coordination and consistency. As such, this paper also uses terms such as source, sink, sending area,
receiving area, and path in the most general of terms and they are intended as engineering or mathematical concepts, not
as the defined usages of those terms.

DETERMINATION OF ATC
ATC is a prediction of the remaining amount of power that could be transferred on a path between two systems for defined
system conditions. AFC is a prediction of the amount of additional power that could flow for defined system conditions over
a particular flowgate, which may involve one or more paths between systems.
The MOD-028 and MOD-029 methods both develop TTC as a prediction of the amount of power that can flow reliably from
one system to another. ATC values are then calculated from the following general equations, and the equations are done
for both firm and non-firm values of ATC, ETC, CBM, TRM, Postbacks, and counterflows. The MOD-030 standard discusses
their method of calculating ATC in the MOD-030 section.
For the MOD-028 and MOD-029 methods, ATC = TTC – ETC – CBM – TRM + Postbacks + counterflows
Where:
•

ATC is the Available Transfer Capability of the transmission path for that period.

•

TTC is the Total Transfer Capability of the transmission path for that period.

•

ETC is the sum of existing transmission commitments of the transmission path for that period.

•

CBM is the Capacity Benefit Margin of the transmission path for that period.

•

TRM is the Transmission Reliability Margin of the transmission path for that period.

•

Postbacks are changes to ATC due to change in use of Transmission Service for that period.

•

Counterflows are adjustments to ATC as determined by the TSP.

1

North American Electric Reliability Council, (1996, June). Retrieved from: http://www.westgov.org/wieb/wind/0696NERCatc.pdf
2
North American Electric Reliability Council, (1999, June 17). Retrieved from:
http://www.naesb.org/pdf4/weq_oasis011513w17.pdf
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Technical Discussion on Various Existing Methods

DETERMINATION OF ETC
ETC can be power flows modeled in the base system conditions, discrete values accounted for in the ATC or AFC calculation,
or both. The ETC value may be a sum of the actual reservation values, an “expected to be used” value, an “effect the value
has on this flowgate or path” value, or a combination thereof.
ETC = NITS + GF + PTP + ROR + OS
Where:
•

NITS is the capacity set aside for Network Integration Transmission Service (including the capacity used to serve
bundled Load within the TSP’s area with external sources) on transmission paths.

•

GF is the capacity set aside for Grandfathered Transmission Service and contracts for energy or Transmission
Service, where executed prior to the effective date of a TSP’s Open Access Transmission Tariff or safe harbor tariff
on transmission paths that serve as interfaces with other Balancing Authorities.

•

PTP is the capacity reserved for confirmed Point-to-Point Transmission Service.

•

ROR is the capacity reserved for rollover rights for Transmission Service contracts granting Transmission Customers
the right of first refusal to take or continue to take Transmission Service when the Transmission Customer’s
Transmission Service contract expires or is eligible for renewal.

•

OS is the capacity reserved for any other service(s), contract(s), or agreement(s) not specified above using
Transmission Service, including any other adjustments to reflect impacts from other transmission paths of the TSP.

DETERMINATION OF CBM
CBM is defined as the amount of firm TTC preserved by the TSP for an Load Serving Entity (LSE), whose Loads are located on
that TSP’s system, to give LSEs access to generation from interconnected systems to meet generation reliability
requirements. Preservation of CBM for an LSE allows that entity to reduce its installed generating capacity below that which
may otherwise have been necessary without interconnections to meet its generation reliability requirements. The TTC
preserved as CBM is intended to be used by the LSE only in times of emergency generation deficiencies.
CBM is not the same as TRM, and components that are included in TRM cannot be included in CBM. The direct beneficiaries
of CBM are the LSEs that are network customers (including native Load) of a host TSP. The benefit that LSEs receive from
CBM is the sharing of installed capacity reserves elsewhere in the transmission system, which translates to a reduced need
for installed generating capacity and, ultimately, lower rates for customers.
CBM is the translation of generator capacity reserve margin determined by (or for) the LSEs within a host TSP into a transfer
capability quantity. It is the TSP’s responsibility to make this translation and as such, the TSP may apply discretion in
determining this quantity. The planned purchase of energy to serve network Load (including native Load) or meet
generation reserve levels is not included in the CBM quantity. These planned purchases actually reduce the total CBM
quantity. For example, if an LSE requires 4,500 MW of external resources and plans the explicit purchase of 1,000 MW, then
the total CBM is 3,500 MW.
Generation Capability Import Requirement (GCIR) is the amount of generation capability from external sources identified by
an LSE or RP to meet its generation reliability or resource adequacy requirements as an alternative to internal resources.
The GCIR may be determined via three methods:
•

Probabilistic Method — Probabilistic calculation methods, such as loss-of-Load probability, have inputs such as unit
forced outages, maintenance outages, minimum downtimes, Load forecasts, etc. A typical benchmark to measure
generation reserve level is a probabilistic loss-of-Load expectation of 0.1 day per year.

•

Deterministic Method — Deterministic methods typically are centered on maintaining a specified reserve or
capacity margin, or may be based upon surviving the loss of the largest generating unit. Typical benchmarks for the
determination methodology would be a multiple of the largest generation unit within the TSP’s system.

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•

External Method — Reserve margin or resource adequacy requirements may be established by other entities, such
as municipalities, state commissions, Regional Transmission Organizations (RTOs), Independent System Operators,
(ISOs), or Regional Entities.

Regardless of method used to determine GCIR, the criteria must be applied consistently by the TSP to all LSEs. In some
cases, it may be appropriate to apply both deterministic and probabilistic methods for the determination of generation
reserve requirements, depending upon the time frame under consideration. For example, in the very near time frame, the
degree of uncertainty associated with generating unit forced and maintenance outages should be low, and deterministic
methods for the calculation of generation reserve requirements may be applied. In this example, for the longer term time
frame, probabilistic methods may be applied due to the number of variables and the uncertainty associated with them.
Regardless of the methodology used, the TSP must ensure that:
1.

The method used to arrive at the amount of external generation needed is consistent with applicable reliability
criteria.

2.

The total transmission capability reserved as CBM on all transmission paths does not exceed the requested GCIR
(less any TRM component).

3.

The allocation of the total CBM to transmission paths is consistent with available external generation resources,
known transmission limitations, and historical transfer patterns during actual emergency generating capacity
deficiency events.

The allocation of CBM to the host TSP’s transmission paths must be based on the generation reserve and projected
availability of outside sources and the historical availability of outside resources. The preservation of CBM on the importing
TSP’s system does not ensure the availability of transmission transfer capability on other systems but relies on the diversity
of generation and transmission resources that may be available on a transmission path during a generation emergency.
Uses of CBM: The TSP that maintains CBM shall approve, within the bounds of reliable operation, any Arranged Interchange
using CBM that is submitted by an “energy deficient entity” under an EEA 2 if:
1.

the CBM is available,

2.

EEA 2 is declared within the Balancing Authority Area of the “energy deficient entity,” and

3.

the Load of the “energy deficient entity” is located within the TSP’s area.

CBM must be released on a non-firm basis when an EEA 2 is not in effect within the Balancing Authority Area of the “energy
deficient entity.”

DETERMINATION OF TRM
TRM is defined as the amount of transmission transfer capability necessary to provide reasonable assurance that the
interconnected transmission system will be secure. TRM accounts for the inherent uncertainty in system conditions and the
need for operating flexibility to ensure reliable system operation as system conditions change.
Generally, the uncertainties associated with the operation of the interconnected electric system increase as the time
horizon increases. Examples of these uncertainties are:
•

Aggregate Load forecast

•

Load distribution uncertainty

•

Forecast uncertainty in transmission system topology (including, but not limited to, forced or unplanned outages
and maintenance outages)

•

Allowances for parallel path (loop flow) impacts

•

Allowances for simultaneous path interactions

•

Variations in generation dispatch (including, but not limited to, forced or unplanned outages, maintenance outages
and location of future generation)

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•

Short-term System Operator response (including Operating Reserve actions)

•

Reserve-sharing requirements

•

Inertial response and frequency bias

The methodology used to derive TRM and its components must be documented and ideally should not account for
uncertainties accounted for elsewhere in ATC calculation.
This paper’s purpose is not to describe the detailed process of the calculation methodologies by which TRM is determined,
but rather to delineate the thought process to derive a TRM quantity. It is a TOP’s task to determine the justification and
calculation methodology for any of the uncertainties listed above. To illustrate a justification and calculation methodology,
two examples for determining the short-term System Operator response (Operating Reserve actions) component of TRM
are given below.
•

Example #1: The first method explicitly models Operating Reserves in the calculation of TTC by replacing lost
generation based on a call for operating reserve sharing. If the generator contingency is more restrictive, the limit,
due to implementation of the operating reserve sharing, sets the amount of TTC. If the transmission contingencies
are all more restrictive, the transmission contingency limit will set the amount of TTC. If a generator contingency
occurs, resulting in the need to access operating reserves, it will produce lower loadings than the transmission
contingency. This method may be appropriate when monitoring all transmission facilities in the interconnected
transmission system.

•

Example #2: The second method simulates the loss of individual generators with replacement power modeled as a
call for operating reserve sharing via power flow analyses. The maximum increased flow on a transmission path or
flowgate becomes the operating reserve sharing component of TRM. This method may be more appropriate when
monitoring a limited number of facilities or flowgates similar to the TRM applied by transmission path.

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Area Interchange Method – MOD-028
PROCEDURE FOR CALCULATING AREA INTERCHANGE METHOD
Determination of TTC in the Area Interchange method is based on predicting the system response to power flowing from
one area of the system to the other. This prediction is made by stressing the system with appropriate transfers under
critical contingencies to determine the response of the transmission system.
When power is transferred between two areas (such as Area A to Area F in the figure below), the entire transmission
system responds to the transaction. The power flow on each transmission path will change in proportion to the response of
the transmission path to the transfer. Similarly, the power flow on each transmission path will change depending on
network topology, generation dispatches, customer demand levels, other transactions through the area, and other
transactions that the transmission path responds to that may be scheduled between other areas.

Area A

Area C

Area B

Area D

Area E

--22%

Area F

Figure 1. Response for Area A to Area F Transfers
Transmission studies are performed to determine the transfer capability from Area A to Area F. During the studies, it is
determined that 77% of power transfers from Area A to Area F on the transmission path between Area A and Area C. In this
example, 160 MW of pre-existing power flows from Area A to Area C due to generation dispatch and the location of
customer demand centers on the modeled network. When a 500 MW transfer is scheduled from Area A to Area F, an
additional 385 MW (77% of 500 MW) flows on the transmission path from Area A to Area C, resulting in a 545 MW power
flow from A to C (385 MW + 160 MW). To determine the ability of the transmission system to transfer power from Area A
to Area F, additional potential impacts within the individual area must also be recognized. The transmission system
responses shown in Figure 1 must be expanded to consider possible transmission limits within each area. Recognition of the
limiting element responses within the individual areas for Area A–Area F transfers increases the complexity of determining
the Area A–Area F transfer values.

TRANSLATION OF SYSTEM IMPACTS TO TTC
TTC is a function of total capacity availability on the most limiting transmission facility that allows for single facility and, in
some cases, multiple facility contingencies. To determine TTC, the Incremental Transfer Capability (ITC) is first determined.
ITC the measure of, from a certain starting system condition, how much additional capacity can be transferred from Area A
to Area F before pre- or post-contingency limit(s) are reached. Once this ITC limit is found, it is combined with the existing
transfers from Area A to Area F, referred to as the “impact of firm,” to come up with the total transfer capability between
the areas based on simulation. The TTC used to determine ATC must also be lower than the contractual rights (for example
sum of ties), and lower than any predetermined SOL or IROL value for that path or a combination of paths. The TTC value
may also have to consider other obligations that may limit its value; for example, if multiple paths share an interface limit
and each has an allocated portion of that interface limit, the allocated portion of the interface limit may be lower than the
calculated value. So the TTC value used to determine ATC is the lowest of these values.

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TTC is the lowest of:
•

ITC value + impact of firm

•

Contractual rights (sum of ties, contracts)

•

Agreed-upon allocations

•

SOL or IROL value previously determined through other studies

ATC TIME VARIATION AND NETWORK DEPENDENCY
Network conditions will vary over time, causing the resultant ATC of the network to change. Also, the most limiting facility
in determining the network’s ITC can change from one system condition to another. Therefore, the ATC of the network
changes as the expected conditions for the time period under study changes, or the time period being evaluated changes.

ADDITIONAL COMMENTS ON DETERMINATION ON AREA INTERCHANGE METHOD OF TTC
The major points for determining a Network Response Total Transfer Capability are outlined below.
1.

System Conditions: Base system conditions are identified and modeled for the period being analyzed, including
projected customer demands, generation dispatch, system configuration, and base scheduled transfers. As system
conditions change, the base system conditions under which TTC is calculated may also need to be modified.

2.

Critical Contingencies: During transfer capability studies, many generation and transmission system contingencies
throughout the network are evaluated to determine the most restrictive contingency(s) to the transfer being
analyzed. The contingency evaluation process includes a variety of system operating conditions, because the most
critical system contingencies and their resulting limiting system elements vary.

3.

Parallel Path Flows: Parallel path flows occur as a result of power transferred in the ac network. This complex
transmission system phenomenon can affect one or more Area’s transmission line(s), especially those Areas
electrically near the source or sink of the loop flow. As a result, transfer capability determinations must be
sufficient in scope to ensure that limits throughout the transmission system are addressed. In some cases, the
parallel path flows may result in transmission limitations in systems other than the Area with the source and sink,
which can limit the transfer capability between those two areas.

4.

Non-Simultaneous and Simultaneous Transfers: Transfer capability can be determined by simulating transfers from
one area to another independently and nonconcurrently with other area transfers. These capabilities are referred
to as “nonsimultaneous” transfers. Another type of transfer capability reflects simultaneous or multiple transfers
concurrently. These capabilities are developed in a manner similar to that used for non-simultaneous capability,
except the interdependency of transfers among other areas is taken into account. These interdependent
capabilities are referred to as “simultaneous” transfers. No simple relationship exists between non-simultaneous
and simultaneous transfer capabilities. The simultaneous transfer capabilities may be lower than the sum of the
individual non-simultaneous transfer capabilities.

5.

Maximum Adjustment Applied: Depending on the exact method of determining an ITC value, the calculation may
run out of adjustments to make (Load or generation) without finding a constraint to ITC. At this point, the ITC value
may be set at the maximum amount tested, the Maximum Adjustment Applied value. If the Maximum Adjusted
value is the ruling factor in the end ATC value, the value should be high enough that the end ATC value does not
constrain the market.

Rated System Path Method – MOD-029
OVERVIEW
The RSP method for ATC calculation is typically used for transmission systems that are characterized by sparse networks
with customer demand and generation centers distant from one another. Generally in this approach, transmission paths
between areas of the network are identified and appropriate system constraints determined. ATC is computed for these
identified paths and interconnections between TSPs.
The current RSP method defined in MOD-029 is generally developed from the WECC RSP method. The process of
determining the TTC is currently based on operating horizon simulated power flow: either no reliability limit is achieved, or
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reliability limit is achieved. This has been identified as an issue in the current MOD-029. Generally, the RSP method involves
three steps:
1.

determining the path’s TTC;

2.

allocating the TTC among owners in a multiowned path to determine the owners’ rights; and

3.

calculating ATC for each right-holder by subtracting each of their uses from each of their individual TTC rights.

With regard to the regional path (such as a WECC Rated Path), wide-area coordination is achieved by developing the TTC in
a manner that follows a regional review process. This process assures individual, power pool, subregional and regional
coordination and the necessary consideration of the interconnection network’s constraints and conditions. While this
coordination could be achieved for a system intact (all lines in service) and a specific set of planned outages, it is very
difficult to ensure that the TTC for all paths (including internal paths) is always coordinated for the time horizon for those
RSPs, because system topology changes with all the planned outages, demand forecasts, and generation schedules. The RSP
method includes a procedure for allocating TTC, and in turn ATC, among the owners of the transmission paths.

UNSCHEDULED FLOW OR PARALLEL PATH FLOW
The RSP approach to calculating TTC may or may not account for the effects of unscheduled flow (parallel path flow) on
interconnected systems through the modeling of realistic customer demand and generation patterns in advance of realtime operations. It uses a maximum power flow test to ensure that the transfer path is capable of carrying power flows up
to its rated transfer capability or TTC.
The rating process begins by modeling the interconnected network with the actual flow that will occur on the path and its
parallel paths under realistically stressed conditions. The lines comprising the path may be rated and operated as a single
path. The network is tested under a wide range of generation, customer demand, and facility outage conditions to
determine a reliability-based TTC. When determined this way, the TTC rating usually remains fairly constant except for
system configuration changes such as a line outage. To implement the RSP method, consistent path rating methods and
procedures must be agreed upon and followed within the interconnection.
Nonsimultaneous ratings are normally used as the basis for calculating ATC. If, however, two rated paths have a
simultaneous effect on each other, the rating process identifies the simultaneous capabilities or establishes nomograms
that govern the simultaneous operation of the paths. Applicable operating procedures are negotiated to ensure reliable
network operation. Where simultaneous operation is necessary, operator control is used to ensure safe and reliable
operation of the transmission network.
TTC values are calculated for operating time horizon in some path with native and a neighboring control area’s forecasted
Loads, generation schedules, and line outages. ATC will change as a result of the operating horizon TTC changes for that
time horizon. Pre-contingency limits for all facility ratings are respected while post-contingency limits are set for Long-Term
Emergency (LTE) and Short-Term Emergency (STE) ratings with respect to facilities owned by a TOP and its neighboring
control area’s facilities.

CAPACITY ALLOCATION
The TTC of a transmission path is allocated among the right-holders based upon their negotiated agreements. The
determination of the transmission rights through the allocation process is critical to the RSP implementation of ATC. The
rights in the path are negotiated for each of the individual TSPs. Except for deratings based upon system operating (e.g.,
emergency) conditions, these allocations become rights that the right-holder may use or resell as Transmission Service.
Although the actual flows from each right-holder’s schedule will flow on all parallel lines, the advance allocation of rights on
a path makes it possible for right-holders to determine ATC and sell Transmission Service within their rights, independent of
others. If the rating is determined using appropriate path-rating procedures, including a maximum power flow test, the
potential for adverse unscheduled power flow effects is minimized.

ATC CALCULATION APPROACH
1.

Each path for which ATC must be calculated is identified, and then a TTC is determined as described above. The
TTC is then allocated among the owners by negotiated agreement.
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2.

Deratings for outages, nomograms, maintenance, or unscheduled flow are allocated, if necessary, to the rightholders based on prearranged agreements or tariffs.

3.

Right-holders take their respective allocated shares of the TTC for a path and subtract the existing commitments to
determine the appropriate ATC.

4.

Right-holders update and repost their ATC calculations as new commitments impact their ATC. A transfer from one
area to another involving several Transmission Owners (TOs) requires locating and reserving capacity across
multiple paths and potentially multiple right-holders.

EXAMPLE OF ATC DETERMINATION
The following example illustrates the application of the RSP method for determining ATC in a sparse network. The example
transmission system is shown in the figure below. All paths that connect the various areas have transfer capabilities that
consider unscheduled flow and interconnection interactions and effects and were individually developed in coordination
with all areas. The TTCs portrayed in the figure are shown for each path and are directional, but are not necessarily the
same for each direction.

Figure 2. Example Application of Using RSP to Determine ATC in a Sparse Network
Each path may consist of several transmission lines that can have different owners. In the example shown in Figure 2, the
path between Area B and Area D is comprised of five lines. The TTC from Area B to Area D is 7,500 MW and in the reverse
direction is 8,800 MW. Line 1 is owned by a single entity and has an allocated portion of the TTC equal to 1,300 MW in
either direction.

Figure 3. Example Application of using RSP to Determine ATC with Multiple Owners
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The example illustrated in Figure 3 reflects a snapshot in time during the planning horizon. Initial Transmission Service
reservations are shown for each path in the figure below. The corresponding ATC for each path has been calculated by
subtracting the firm service from the TTC. Because all the Transmission Service reservations are assumed to be in one
direction on each path, the path ATC is only calculated for that direction.

Figure 4. Example of a Snapshot in Time Using RSP to Determine ATC
In the example shown in Figure 4, the ATC from Area B to Area D is calculated as 7,500 MW less 4,000 MW, or 3,500 MW.
For line 1 of the Area B-to-Area D path, the ATC is 1,300 MW less 200 MW, or 1,100 MW. In the next case, as shown in
Figure 5 below, 1,000 MW of firm Transmission Service is acquired from Area A to Area B to Area D. No other changes
occur. The total Transmission Service reserved from Area A to Area B is 1,500 MW, and the resulting ATC goes to zero. The
ATC from Area B to Area D reduces to 2,500 MW (7,500 MW TTC less 5,000 MW reserved Transmission Service). It is
assumed the 1,000 MW of the new reserved Transmission Service was obtained from the owner of line 1, resulting in the
total reserved Transmission Service on this line being 1,200 MW. The new ATC for line 1 is 100 MW (1,300 MW TTC less
1,200 MW reserved Transmission Service).

Figure 5. Example of a Snapshot in Time Using RSP to Determine ATC
The non-firm Transmission Service reserved for a path in each direction may not exceed the path’s transfer capability in
either direction under any circumstances.

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Unscheduled flow may at times preclude scheduling to a path’s full transfer capability or TTC. If an internal limit is
encountered in any system as a result of the transaction from Area A to Area D (for example in Area D), Area D’s system
operator must respond to relieve the limitation by redispatching generation or using phase shifter control. An unscheduled
flow mitigation plan might also be implemented to relieve excessive unscheduled flow problems. Additional relief may be
achieved by curtailing schedules that are contributing to the unscheduled flow on the path or by increasing schedules that
would create unscheduled flow in the opposite direction. In this example, if the path from Area A to Area D were limiting,
unscheduled flow mitigation procedures could be implemented to initiate coordinated operation of controllable devices
such as phase-shifting transformers to relieve the limitation.
There are times in the operating horizon when the use of the transmission system results in actual flows on a transmission
path being less than the transmission scheduled on the path. During these periods, if the transmission path is fully
scheduled, additional electric power may be scheduled to Area D from Area A by reserving Transmission Service over a
different transmission path. In this case, Transmission Service could be obtained from either the owners of the direct path
between Area A and Area D or the owners of the transmission system from Area A to Area C to Area D.
For the RSP method, the transmission rights to be reserved and scheduled by all transmission users are consistent with the
rating of the transmission paths. If determined through a coordinated process using models that capture the major effects
of the interconnected network, these ratings will create limits that result in the reliable operation of the regional electric
system. Through a negotiated allocation process, the owners of the transmission paths will know their Transmission Service
rights, and the resulting use of these rights will be consistent with the physical capability and limitations of the transmission
system.

Flowgate Method – MOD-030
PROCEDURE FOR CALCULATING FLOWGATE METHOD
The Flowgate Methodology uses a flow-based approach to calculate ATC based on a predetermined set of constraints—a
subset of monitored and contingent elements called flowgates. AFC is the amount of unused transfer capability on a
flowgate after accounting for base case conditions represented by solved base case flows and applying the impacts of nonbase case commitments and flowgate specific margins.
The following mathematical algorithm is used to calculate AFC:
AFC = TFC – ETC – TRM – CBM + Postbacks + counterflows
Where:
•

AFC is the Available Flowgate Capability for the flowgate for that period

•

TFC is the Total Flowgate Capability of the flowgate

•

ETC is the sum of existing transmission commitments for the flowgate during that period

•

CBM is the impact of the Capacity Benefit Margin on the flowgate during that period

•

TRM is the impact of the Transmission Reliability Margin on the flowgate during that period

•

Postbacks are changes to AFC due to change in use of Transmission Service for that period

•

Counterflows are adjustments to AFC as determined by the TSP

To calculate ATC, which represents a transfer capability in MW available for sale between a specific POD and POR, the TSP
will first calculate an AFC for each flowgate. ATC is then calculated by taking the minimum AFC of the limiting flowgates per
path and dividing it by the distribution factor or transfer response factor.
ATC = Minimum {AFC1 / Transfer Response Factor, …, AFCn / Transfer Response Factor}
Where n is the number of limiting flowgates for a specific POR and POD Pair.
ATC determination process is a multistep integrated process:

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•

The TSP develops and maintains seasonal models and performs AFC or ATC calculations based on them. The
model builder portion of the AFC or ATC engine modifies these seasonal base cases to reflect anticipated
conditions such as forecasted Load levels, outages, generation dispatch files, and base case transfers (reservations
or schedules as appropriate) for the AFC or ATC time horizon. The base case is used to calculate initial AFC
flowgate values and transfer distribution factors, which in turn are inputs to the ATC calculation process.

•

The ATC calculation process applies the impacts of transmission reservations (or schedules as appropriate), TRM,
and CBM and calculates AFC by determining the capacity remaining on individual flowgates for further
Transmission Service activity. The AFC calculation uses the AFC values for selected coordinating entity flowgates
that are calculated by the coordinating TSP.

•

The TSP’s AFC or ATC calculation implements the following principles for firm and non-firm ATC calculations: (1)
for firm ATC calculations, the TSP accounts for firm commitments; (2) for non-firm ATC calculations, the TSP
accounts for both firm and non-firm commitments.

•

Using transfer response or distribution factors for the specific POR and POD pairs, the AFC–ATC calculator
translates the flowgate AFC values into path ATC values for postings on the Open Access Same-Time Information
System OASIS.

Flowgate Criteria
The TSP models some flowgates with contingencies and some without contingencies. The flowgates modeled without
contingencies are the Power Transfer Distribution Factor (PTDF) flowgates, which are flowgates where a single facility or
multiple transmission facilities are monitored for a limiting condition. The flowgates modeled with contingencies are the
Outage Transfer Distribution Factor (OTDF) flowgates, which are flowgates where a single facility or multiple transmission
facilities are monitored for a limiting condition after a contingency event has been simulated to have occurred (one or
multiple facilities for the loss of another facility or facilities).
The flowgate screening process for AFC calculations includes at a minimum the top three limiting elements based on a BA–
BA transfer analysis. The TSP also includes applicable SOL and IROL flowgates. In addition, flowgates with a history of
Transmission Loading Reliefs (TLRs) are included in the AFC process.
The TSP also includes external entity flowgates with a 5% distribution factor in the AFC process. PTDF or OTDF is applied as
appropriate to the Flowgate, as defined by the requesting TSP.
For flowgates owned by other parties, the TSP uses the limit provided by that party, subject to the terms of the AFC
coordination and congestion management process sections of the applicable agreements between the TSP and the other
parties.

ATC Calculation Example
The following example illustrates the application of the flowgate method to calculate ATC. The transfer between Areas A
and B is limited by flowgates 1, 2, and 3. Flowgate 2, with the minimum ATC, establishes the path ATC for the specified time
period. The details of the calculations are below.

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AFC final = RATING − FLOW − CBM − TRM − RESERVATION IMPACTS *
ATC =

AFC final

dfax
* Reservations not already included in the base case

Flowgate 1 : AFC1 = 1000 − 800 − 30 − 20 − 50 = 100 MW
ATC1 = 100 0.40 = 250 MW
Flowgate 2 : AFC 2 = 880 − 700 − 35 − 25 − 55 = 65 MW
ATC 2 = 65 0.3 = 217 MW
Flowgate 3 : AFC 3 = 800 − 500 − 24 − 16 − 135 = 125 MW
ATC3 = 125 0.4 = 312 MW

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Other Technical Discussions
The main discussion points raised by the informal development group are summarized below. These discussions provided
the basis for the consolidation of the six MOD A standards and specifically for determinations regarding which requirements
were necessary for reliability and which requirements were market-based. This section is intended to assist anyone who
was not able to participate in the informal development process in understanding why the informal development resulted
in the posted pro forma standard. In addition, this section will provide the standard drafting team the rationale behind the
proposed changes.

Respecting and Utilizing Neighboring Systems Data
The group discussed how the industry sells Transmission Service. They determined that while the selling of service itself is
not a function of system reliability, the excessive selling of transmission can create otherwise unnecessary actions by the
TOP to maintain system reliability. The first step a TSP can take to ensure its calculated ATC does not impact reliability is to
limit the sale of Transmission Service to within SOLs or IROLs. The second step a TSP can take is to limit the calculated ATC
to within the SOLs or IROLs of neighboring TSPs, provided the sale of that service has an impact upon those SOLs or IROLs.
The current MOD standards go into great detail to provide prescriptive methods for identifying those SOL or IROLs that
could be impacted by transactions that result in the sale of Transmission Service.
The ad hoc group determined that any new or revised standard developed needs to retain a framework for requiring TSPs
and their neighboring TSPs to share and acknowledge mutual impacts on SOLs or IROLs. This would allow the continued
coordination between TSPs such that SOLs or IROLs are not intentionally violated by the sale and scheduling of
Transmission Service. This type of TSP coordination is essential and provides an additional layer of situational awareness for
securing the reliability of the BPS by the TOP. This is especially true in the MOD-030 standards, where the identified limits
are a monitored element or contingency pair that could become an SOL or IROL or facilities that have gone through the
congestion management process within the last year.

Operating the System
One of the key components of operating the transmission system is the communication and coordination of BPS SOLs and
IROLs in the operating horizon. This communication and coordination allows Reliability Coordinators (RCs) and affected
TOPs to have situational awareness of issues in neighboring transmission systems that may have an impact on their own
transmission systems. It also allows the affected TOPs to take corrective actions necessary to mitigate the potential threat
to the BPS as a result of these SOL or IROL violations.
Another key component is monitoring system conditions in the operating horizon. The TOP continuously monitors real-time
activities on the BPS and verifies that their transmission systems operate within SOLs and IROLs. The TOP monitors daily
operating conditions and the execution of mitigation plans in order to ensure that the corrective actions taken to mitigate
SOLs or IROLs are valid. During daily and seasonal assessments, the TOPs are made aware of potential SOLs or IROLs so that
mitigation plans can be developed and validated.
Any new or revised MOD standard should retain those requirements that provide for the communication, coordination, and
monitoring of SOLs and IROLs.

Oversold Conditions
NERC defines ATC as a measure of the transfer capability remaining in the physical transmission network for further
commercial activity over and above already committed uses. As such, ATC is a calculation of how much capacity a TSP is
willing to make available to transmission customers, balanced against TSP and transmission customers’ willingness to
accept increased curtailment or redispatch risk. This risk tolerance is unique to each TSP and is based on their estimates of
how much committed capacity may be used at a given point in time. Accurately estimating how transmission customers
will exercise their committed capacity is becoming increasingly difficult, given the proliferation of variable resources and
renewable portfolio standards that encourage customers to purchase transmission rights in excess of their needs, so that
they maintain flexibility to use energy from a number of different resources.

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Other Technical Discussions

ATC is not a prediction of unused transfer capability and, in most cases, does not directly inform the dispatch or operations
of transmission systems as to system loadings. For example, a negative ATC value would not necessarily trigger corrective
actions until the constraint is overscheduled, real-time system loadings approach system limits, or the system limit (SOL or
IROL) is violated. The prediction of ATC values at a particular time or day changes as Load forecasts, outage plans, and
other system condition forecasts change. As it approaches real time, a daily transfer sold 28 days out may vary from
unconstrained market conditions, to constrained, to oversold, and back to unconstrained as forecast data changes. The
service is sold based on the party’s risk tolerance for curtailment and prediction of future conditions, realizing that as real
time approaches, those conditions may change. While the services are sold in good faith, a service sold will not be
scheduled and delivered if it will cause an SOL or IROL violation when it comes to real-time operation.

Conclusion for Revising the Standards
As discussed above, there are existing standards and practices that dictate the operation of the system. The ATC or AFC
value provides a forecast of what additional capacity may be available for sale, given the current prediction of future
conditions, but those values do not dictate how a system will operate. Since overselling can create the burden on TOPs to
make curtailments that may have been avoidable, there is a reliability need for the TSP to disclose to the TOP, neighboring
TSPs, and others how they determine that available capacity. There is also a reliability need for those calculations to
respect the SOL or IROL values of the TOPs and for TSPs to share data with each other as needed to calculate ATC values.
Just as existing standards do not provide the formula to solve a Load flow calculation, or how to solve for voltage given
current and impedance, there is no reliability need served by having the standards prescribe a series of methods for
determining ATC or AFC values. In some cases this prescriptive approach harms reliability or harms market access by either
overcalculating or undercalculating the ATC or AFC value, depending on the particular approach and the system to which it
is applied.

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Proposed Resolution
Role of the Existing Standards
As discussed above, the role of NERC ATC and AFC standards is reliable TTC and TFC calculation, transparency in ATC or AFC
calculation, and data sharing. The existing ATC- and AFC-related standards, MOD-001, MOD-004, MOD-008, MOD-028,
MOD-029, MOD-030, go well beyond this role by specifying the mechanisms the TSP or TOP should use to determine the
TTC, TFC, CBM, ETC, ATC, and AFC values. An entity that calculates TTC in a technically sound manner that respects the
reliability limits, but doesn’t necessarily follow one of the predetermined methods, would not adversely affect reliability.
The high level of detail and instructions in the standards also limit the ability to innovate and find more efficient or more
accurate methods of determining ATC and AFC values that may result in better reliability, better market access, or both.
This high level of detail also dilutes the focus on the key reliability elements of the standards. The existing standards are
also only invoked when the values are used in an ATC or AFC calculation, so a TOP that calculates TTC or TFC for use in
operating its system or to support its RC would not fall under the current standard unless the values were also used for ATC
calculation. Therefore, the ad hoc group proposes that the pro forma standard consolidate the reliability needs of the
existing standards into a single standard.

Transition Considerations Created by Consolidation of the Existing
Standards
The ad hoc group identified important considerations as it examined consolidating the MOD A standards, including what
role NAESB or another organization could take in addressing requirements that were not going to be owned by NERC. These
transition considerations were reliability, transparency, and consistency.
The ad hoc group discussed these transition considerations at length and came to the conclusion that for the perspective of
reliability, the proposed pro forma standard does not harm BPS reliability. For the purposes of transparency, the pro forma
standard maintains and may improve upon the level of transparency that the existing standards provide. For consistency,
the pro forma standard does allow for more variety than the current three methods (MOD-028, MOD-029, and MOD-030)
allow, but that may not be detrimental to reliability and market access. However, the ad hoc group does not believe this
variety is detrimental to reliability. The role of NAESB (or another organization) in picking up where the standard drops off
must still be fully determined and will be during the coming weeks, before this filing is submitted to FERC for approval.
The pro forma standard focuses on what the ad hoc group believes are the reliability needs around TTC, TFC, TRM, CBM,
ATC, and AFC. Those three reliability needs are the sharing of how a value is calculated, an opportunity to influence that
value, and data sharing. Across North America, there are several variations on how to determine these values based on the
specific transmission system conditions, market conditions, and available data. These methods all fall broadly within the
existing MOD-028, MOD-029, and MOD-030 standards and have been developed over the last several years by those
knowledgeable in how their transmission systems respond to stimuli. Since no single method provides the right balance of
reliability and market access for all areas, attempting to provide a single method, or even three single methods of
instruction, does not improve reliability. This approach also follows the NERC philosophy that standards should focus on
results, not on methods. The results that the pro forma standard focuses on are clear communication of method,
opportunity for influence, and data sharing; the standard, however, does not focus on the method for achieving them. In
addition, while reducing the number of requirements, the pro forma standard actually addresses an existing reliability gap:
the calculation of TTC or TFC by a TOP that is needed either by its RC or in its own operation of the system is now brought
within the standard. In the past it would not have been addressed if not part of an ATC or AFC calculation.
The pro forma standard maintains the current state of transparency in the calculation of TTC, TFC, TRM, CBM, ATC, and AFC
values. Like the existing ones, this standard requires documentation and disclosure of practices. By removing the
instructional portions of the standard, the revised standard should improve transparency; the calculation method can be
discussed as a story from start to finish using specifics and terms from the provider’s actual process and software, rather
than entities translating them into the instructions of the prior standard. The pro forma standard maintains the current
level of transparency and may improve the quality of communications by removing a rigid framework to which the current
descriptions must conform.

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Proposed Resolution

Consistency with regard to ATC, AFC, TTC, TFC, CBM, TRM, is a topic with four considerations to address. The first
consideration is that the existing standards have not necessarily resulted in three methods of calculation. The variety of
methods all fit under one of the three umbrella standards (MOD-028, MOD-029, MOD-030), but there are still very distinct
differences in methods. The mandatory standard, market needs, corporate mergers, and technological advances heavily
influenced the consolidation that has occurred over the last 10 years, but the influence of the codification of three methods
may have been limited. Eliminating the codification will not remove the other pressures to consolidate methods. The
second consideration is that the existing umbrella standards, while written to encompass the best reliable practices at the
time and anticipated in the future, did not represent a new method of calculation. Instead, they were more a
documentation of existing methods. As such, in many cases if those umbrella standards are retired, their absence will not
drive an entity to change its operating practices. Entities may revise their implementation documents to fit the method
more naturally than the standard-driven format of the description; this only improves the transparency, not the consistency
of application. The final point is that if an entity does adjust its method (rather than just the description) because of the
umbrella standards going away, it is not necessarily detrimental to reliability or to the market. If an entity is adjusting its
method, it is likely due to market pressures, improvements in calculation efficiency, or reliability enhancements, none of
which are detrimental to market access or reliability. The ad hoc group also elaborated on the three umbrella methods
within this technical paper with the intent that the formal standard drafting team will further revise those descriptions and
publish them as white paper. This would help address consistency since it would give another common reference for
entities to look at when developing and describing ATC or AFC methods.
The proposed retirement of MOD-028, MOD-029, and MOD-030 does reduce the amount of regulation or structure in how
the calculations are performed. The ad hoc group is helping to address this through their inclusion of instructional material
on the methods within this paper. The group notes that most entities will not significantly change their techniques due
solely to the reduction in standards requirements.

Purpose and Placement of the Pro Forma Standard
The revised standard serves three purposes. The first is to ensure reliable calculation of TTC and TFC values when
calculated. The second is to ensure transparency and communication with the TOP, the RC, and other registered entities
that may have a reliability need to understand how TTC, TFC, TRM, CBM, ATC, and AFC are calculated. The third is the
sharing of data with other TOPs and TSPs to support their calculations of these values.

Calculation of Total Transfer Capability and Total Flowgate Capability –
Addressed in Requirement R1 of Pro Forma Standard
TTC and TFC can be calculated by a TOP or a TSP either to support the determination of ATC or AFC, to support the RC, to
support system operations, or a combination of reasons. Regardless of the reason, the TTC and TFC values (if calculated)
need to have a sound basis and be derived from the system limits (e.g., facility ratings, stability limits, voltage limits, preand post-contingency conditions, or an SOL). Because the calculation of TTC or TFC can affect a neighboring TOP, the
entity’s calculation must include constraints identified by a nearby TOP. This assures that the TTC or TFC value protects the
reliability of the entire BPS, not just the calculating TOP’s system. Just like the calculation of SOLs, IROLs, and facility ratings,
it is not necessary to reliability to specify the exact method of reaching the end value—only that the end value protect the
reliability of the BPS. Therefore, the calculation of TTC or TFC by a TSP or TOP must be done in manner that protects BPS
reliability on all affected systems.

Calculation of Available Transfer Capability and Available Flowgate
Capability - Addressed in Requirement R2 of Pro Forma Standard
The selling of service itself is not a function of system reliability; the operating condition of the grid that the TOP and RC
inherit is influenced when the time period for which ATC or AFC was calculated moves into real time. To ensure they are
planning the system as it is being used, the TP and PC may be interested in the TSP’s calculation of ATC and AFC to assure
that the calculations of ATC and AFC respect the reliability limits for which the TP and PC planned the system. The
determination of ETC is considered an integral part of the ATC calculation and is not broken out like TRM and CBM are
below. Understanding how a TSP calculates ATC or AFC is important to system reliability.

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Proposed Resolution

Calculation of Transmission Reliability Margin and Capacity Benefit
Margin - Addressed in Requirements R3 & R4 of Pro Forma Standard
The values of TRM and CBM are components in the determination of ATC; therefore, like ATC, the Transmission Operator
and others have a reliability need to understand how these values are derived (if used) and how they are applied to reach
an ATC value. Because other existing standards and processes reference a CBMID and a TRMID, the ad hoc group retained
these terms for describing CBM and TRM, even though those descriptions could have been included in the ATCID. In
addition, the ad hoc group specified that if an entity does not use CBM or TRM, it should still maintain an implementation
document that states as much. Since many entities that did not maintain CBM and TRM already maintain an
implementation document that said so (to facilitate compliance with NERC standards and other obligations), the ad hoc
group did not believe this was a significant administrative burden. Therefore, understanding how a TSP or TOP calculates
CBM and TRM is important to system reliability.

Sharing Data - Addressed in Requirements R5 & R6 of Pro Forma
Standard
TSPs are often required to calculate ATC or AFC values due to other obligations, and both TSPs and TOPs may be required to
calculate a TTC or TFC value. To meet this responsibility, the pro forma standard would also need to maintain the datasharing requirement found in the current standard. This data-sharing requirement should maintain the same caveats that
the existing standard does regarding only having to share data that the entities own and use in their calculations, as well as
not having to change the data’s format. A caveat should be added that this data sharing may be subject to a confidentially
and security agreement between the entities. Therefore, it is important to reliability that TOPs and TSPs be obligated to
share their data with other TOPs and TSPs for the calculation of TTC, TFC, TRM, CBM, ATC, and AFC values.

Jurisdictional vs. Non-jurisdictional Discussion
The ad-hoc group acknowledges that reliability standards issued under Section 215 of the Federal Power Act (FPA) are
applicable to all owners, operators and users of the BPS in North America, however, FERC jurisdiction over market issues
does not extend to all municipalities and electric cooperatives, which are otherwise subject to FPA Section 215. The pro
forma standard covers reliability-related issues for the MOD A standards and applies to all entities subject to Section 215 of
the FPA. Issues related to market standards, including which entities are subject to those standards, are beyond of the
scope of NERC Reliability Standards.

Feedback from NERC Compliance
The ad hoc group received feedback from NERC Compliance on the use of the phrase “keep current and implement” within
Requirements R2, R3, and R4 of the pro forma standard. The language within those Requirements is for a TSP or TOP to
“prepare, keep current, and implement an ATC, CBM, or TRM (respectively for the Requirements) Implementation
Document.” Specifically, there was a comment as to “…recommends that the MOD A informal ad hoc group either consider
making the requirement time-bound (such as every 12-months) or requiring the registered entity to document in their
processes or procedures the frequency of review (with a not to exceed). Further, the pro forma standard should describe
what constitutes implementation.”
As an example for an entity to prepare, keep current, and implement an ATCID:
1.

Prepare: If an entity calculates ATC or AFC values then that entity must have an ATCID. Almost all entities already
have one, and this component of the phrase would only be focused on a brand new registered TOP or TSP.

2.

Keep current: This component ensures that the entity’s implementation document remains accurate to the
entity’s process. If an entity’s ATCID states to use the “paper amount” of the reservation, but the method changes
in using the expected usage of a reservation instead of the full paper amount, then the entity would be obligated
to keep the implementation document current; preferably changing the implementation document before the
entity changes the actual posted value. What this phrase does not entail is the periodic review to keep current
with industry trends or changes on the system.

3.

Implement: If an entity’s ATCID says “A+B+C=ATC”, then the entity shall demonstrate, through OATI WebTrans or
another tool, that A, B, and C do indeed add up to ATC.
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Outstanding FERC Directives
There are 20 outstanding FERC directives from Order 729. Each of the directives was discussed in detail during the informal
development stage, and summaries of the discussions can be found below. Following the structure for identifying FERC
directives, each directive was given an “S-Ref” identification number (i.e., S-Ref 10283). The ad hoc group extensively
reviewed each of the directives with consideration of where the existing standards are today, where the group landed with
the pro forma standard, and how the group addressed each directive.
3

The “Paragraph 81 initiative”, which was issued by FERC in their March 15, 2012, invited the ERO to identify possible
requirements that could be removed from the NERC Reliability Standards that has little to no effect on reliability. The ad
hoc group has taken the information from the NOPR into consideration when discussing the directives related to the MOD
A initiative.
4

On June 20, 2013, FERC issued a Notice of Proposed Rulemaking (NOPR) identifying 41 possible directives that may be
withdrawn based on (1) whether the reliability concern underlying each outstanding directive has been addressed in some
manner, thus rendering the directive stale; (2) whether the outstanding directive provides general guidance for standards
development rather than a specific directive; and (3) whether the outstanding directive is redundant with another directive.
Of the 41 possible directives, seven have been associated with the MOD A informal efforts. In that NOPR, FERC also
proposed to retire 34 requirements within 19 reliability standards that either: (1) provide little protection for BPS reliability
or (2) are redundant with other aspects of the reliability standards.

S-Ref 10204
129. If the Commission determines upon its own review of the data, or upon review of a complaint, that it should
investigate the implementation of the available transfer capability methodologies, the Commission will need access to
historical data. Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission
directs the ERO to modify the Reliability Standards so as to increase the document retention requirements to a term of
five years, in order to be consistent with the enforcement provisions established in Order No. 670.

Consideration of Directive
Registered entities are required to keep data used in the ATC calculations due to the directives contained within FERC Order
5
670. However, having to reproduce detailed data on a regular basis going back multiple years purely as a compliance
exercise creates an unreasonable burden with no reliability benefit. The group modified the evidence retention
requirements within the pro forma standard to five years for implementation documents and methods but applied a
shorter data retention period for calculations. The group modified the evidence requirements within the pro forma
standard to a graduated time frame for the calculations of hourly, daily, and monthly values based on MOD-028, MOD-029,
and MOD-030 requirements. This is because there is no reliability benefit of having detailed supporting data of the
calculations and that retention of the evidence would serve as an administrative burden.

S-Ref 10206
151. Nevertheless, the Commission believes that the lists of required recipients of the implementation documents may be
overly prescriptive and could exclude some registered entities with a reliability need to review such information.
Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission directs the
ERO to develop a modification to the Reliability Standards pursuant to the ERO’s Reliability Standards development
process to require disclosure of the various implementation documents to any registered entity who demonstrates to
the ERO a reliability need for such information.

Consideration of Directive
The MOD A informal ad hoc group noted that registered entities that have a reliability need for such information should be
able to obtain information from a request for clarification on various implementation documents. Therefore, the group
3

http://www.nerc.com/files/OrderConditionallyAcceptingNewEnfocementMechFiling_031512.pdf
http://www.ferc.gov/whats-new/comm-meet/2013/062013/E-7.pdf
5
http://www.ferc.gov/whats-new/comm-meet/011906/M-1.pdf
4

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Outstanding FERC Directives

included in Requirement R5 of the pro forma standard the obligation for a TOP or TSP to respond to a PC, RC, TOP, TP, TSP,
or any other registered entity that demonstrates a reliability need for disclosure of the various implementation documents,
subject to confidentiality, regulatory, and security requirements.

S-Ref 10207
160. In Order No. 890, the Commission also expressed concern regarding the treatment of reservations with the same point
of receipt (generator), but multiple points of delivery (Load), in setting aside existing transmission capacity. The Commission
found that such reservations should not be modeled in the existing transmission commitments calculation simultaneously if
their combined reserved transmission capacity exceeds the generator’s nameplate capacity at the point of receipt. The
Commission required the development of Reliability Standards that lay out clear instructions on how these reservations
should be accounted for by the transmission service provider. The proposed Reliability Standards achieve this by requiring
transmission service providers to identify in their implementation documents how they have implemented MOD-028-1,
MOD-029-1, or MOD-030-2, including the calculation of existing transmission commitments. Thus we will not direct the ERO
to develop a modification to address over-generation, as suggested by Entegra. Nonetheless, in developing the
modifications to the MOD Reliability Standards directed in this Final Rule, the ERO should consider generator nameplate
ratings and transmission line ratings including the comments raised by Entegra.

Consideration of Directive
This directive may be withdrawn subject to the FERC NOPR issued June 20, 2013. In the NOPR, FERC reasoned that this
paragraph is not a directive to change or modify a standard.
The ad hoc group considered the comments from Entegra regarding generator nameplate ratings and transmission line
ratings. As explained above, this directive relates to ETC, which is a component of ATC or AFC. The pro forma standard
requires disclosure of how the calculation of ETC is done, which would include generator nameplate ratings and
transmission line ratings where appropriate. However, placing specific usage requirements on the TSP would not improve
the quality of communication between the TSP and the TOP (or others) and has little to no impact on reliability. Because
the ad hoc group states this directive is not associated to a reliability-related requirement as noted above, the ad hoc group
proposes that this directive may be considered by NAESB or another standards body through its standards development
process. Removing a requirement or not directly responding to a directive that has little to no impact to reliability is also
consistent with the Commission’s Paragraph 81 initiative.

S-Ref 10208
162. In Order No. 890, the Commission directed public utilities, working through NERC, to modify MOD-010 through MOD025 to incorporate a periodic review and modification of various data models. The Commission found that updating and
benchmarking was essential to accurately simulate the performance of the transmission grid and to calculate comparable
available transfer capability values. On rehearing, the Commission clarified that the models used by the transmission
provider to calculate available transfer capability, and not actual available transfer capability values, must be benchmarked.
Updating and benchmarking of models to actual events will ensure greater accuracy, which will benefit information
provided to and used by adjacent transmission service providers who rely upon such information to plan their systems.
Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission directs the
ERO to develop benchmarking and updating requirements to measure modeled available transfer and flowgate
capabilities against actual values. Such requirements should specify the frequency for benchmarking and updating the
available transfer and flowgate capability values and should require transmission service providers to update their models
after any incident that substantially alters system conditions, such as generation outages.

Consideration of Directive
The ad hoc group considered the directive to developed benchmarking and updating requirements to measure modeled
ATC and AFC values against actual values. The group understands that the underlying assumption in the directive is for
verification of the models against actual values for ATC and AFC. Since the actions that contribute to reliability are the
transparency of the implementation in the calculations of ATC or AFC, the verification of the accuracy of the values is not
reliability-related. Because the ad hoc group states this directive is not associated to a reliability-related requirement as
noted above, the ad hoc group proposes that this directive may be considered by NAESB or another standards body
through its standards development process. Removing a requirement or not directly responding to a directive that has little
to no impact to reliability is also consistent with the Commission’s Paragraph 81 initiative.
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Outstanding FERC Directives

S-Ref 10209
173. The Commission therefore directs the ERO, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, to develop a modification to MOD-028-1 and MOD-029-1 to specify that base generation schedules used in
the calculation of available transfer capability will reflect the modeling of all designated network resources and other
resources that are committed to or have the legal obligation to run, as they are expected to run, and to address the
effect on available transfer capability of designating and undesignating a network resource.

Consideration of Directive
As explained above, this directive relates to the calculation of ATC specifying that base generation schedules used in the
calculation will reflect the modeling of all designated network resources. Requirement R2 of the pro forma standard
requires disclosure of the TSP’s practice in calculating ATC and Requirement R5 requires the TSP to respond to questions
regarding its practice. Between the ATCID and the Requirement to respond to written requests, a TSP’s practices regarding
base generation schedules and the effect of designating and undesignating a network resource will be disclosed to the TOP
and others. The ad hoc group states there is no direct benefit to the reliability of the BPS in setting NERC Requirements on
how generation and network resources are supposed to be handled since that would not enhance the quality of
communication between the TSP and the TOP (or others). The ad hoc group therefore required disclosure of the TSP’s
practices only.

S-Ref 10211
179. We agree that, in order to be useful, hourly, daily and monthly available transfer capability and available flowgate
capability values must be calculated and posted in advance of the relevant time period. Requirement R8 of MOD-001-1 and
Requirement R10 of MOD-030-2 require that such posting will occur far enough in advance to meet this need. With respect
to Entegra’s request regarding more frequent updates for constrained facilities, we direct the ERO to consider this
suggestion through its Reliability Standards development process.

Consideration of Directive
This directive may be withdrawn subject to the FERC NOPR issued June 20, 2013. In the NOPR, FERC reasoned that this
paragraph is not a directive to change or modify a standard.
The ad hoc group considered Entegra’s comments regarding more frequent updates for constrained facilities. Within a
TOP’s or TSP’s documentation and in response to questions from another entity, the TOP or TSP will provide information
regarding the frequency of calculation and the frequency of updates for constrained facilities. This communication with the
TOP and others is not improved by the standard mandating the frequency of calculation or the frequency of updates for
constrained facilities. The issue of more frequent updates for constrained facilities is an issue with commercial access to the
constrained paths and has little to no impact to reliability. Because the ad hoc group states this directive is not reliability
focused as noted above, the ad hoc group proposes that this directive may be considered by NAESB or another standards
body through its standards development process. Removing a requirement or not directly responding to a directive that has
little to no impact to reliability is also consistent with the Commission’s Paragraph 81 initiative.

S-Ref 10212
179. Further, we agree with Cottonwood regarding unscheduled or unanticipated events. Therefore, pursuant to section
215(d)(5) of the FPA and section 39.5(f) of our regulations, we direct the ERO to develop modifications to MOD-001-1 and
MOD-030-2 to clarify that material changes in system conditions will trigger an update whenever practical. Finally, we
clarify that these Reliability Standards shall not be used as a “safe harbor” to avoid other, more stringent reporting or
update requirements.

Consideration of Directive
The ad hoc group considered the directive to clarify that material changes in system conditions will trigger an update
whenever practical. The revised version of the pro forma standard narrows the NERC reliability requirements down to the
core essence of disclosure of practices. In an entity’s ATCID, the TSP will disclose the frequency with which they make
changes to the system in response to events. Rapid updates due to material events are a commercial issue of giving the

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Outstanding FERC Directives

best information to the market; however, since ATC does not directly reflect upon BPS reliability, there is no reliability
benefit to mandate the frequency with which material changes in system conditions trigger an update.

S-Ref 10214
184. As proposed, MOD-001-1 does not restrict a transmission service provider from double-counting data inputs or
assumptions in the calculation of available transfer or flowgate capability. To the extent possible, available transfer or
flowgate capability values should reflect actual system conditions. The double-counting of various data inputs and
assumptions could cause an understatement of available transfer or flowgate capability values and, thus, poses a risk to the
reliability of the Bulk-Power System. We note that, in the Commission’s order accepting the associated NAESB business
standards, issued concurrently with this Final Rule in Docket No. RM05-5-013, the Commission directs EPSA to address its
concerns regarding the modeling of condition firm service through the NERC Reliability Standards development process. We
reaffirm here that modeling of available transfer capability should consider the effects of conditional firm service, including
the potential for double-counting. Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, the Commission directs the ERO to develop modifications to MOD-001-1 pursuant to the ERO’s Reliability
Standards development process to prevent the double-counting of data inputs and assumptions. In developing these
modifications, the ERO should consider the effects of conditional firm service.

Consideration of Directive
The ad hoc group considered the directive to prevent double-counting of data inputs and assumptions. The existing
standards of MOD-028, MOD-029, and MOD-030 each do a thorough job to ensure there is no double counting. Each
method for calculating ATC or AFC is equal to the ETC + TRM + CBM + Postbacks + counterflows. MOD-008 has language
which states you cannot double count between CBM and TRM, which now leaves only ETC as a candidate for double
counting. However, each standard has descriptive requirements that do not allow you to double count. Finally, Postback
and counterflow methods are to be described in an entity’s ATCID. Consistent with the approach of the ad hoc group in pro
forma standard, the transparency and disclosure of a TSP’s ATCID will not allow for double counting. With regards to
network service, this is more of a concern of customers inappropriately reserving service to game the system, and this
behavior would better be suited as a consideration for a market monitoring function under NAESB or another standards
body and not appropriate within the NERC Reliability Standards. Therefore, not directly responding to a directive that has
little to no impact to reliability is also consistent with the Commission’s Paragraph 81 initiative.

S-Ref 10215
192. In its filing letter, NERC states that it requires applicable entities to calculate available transfer capability or available
flowgate capability on a consistent schedule and for specific time frames. In keeping with the Commission’s goals of
consistency and transparency in the calculation of available transfer capability or available flowgate capability, the
Commission finds that transmission service providers should use consistent modeling practices over different time frames.
If a transmission service provider uses inconsistent modeling practices over different time frames that should be made
explicit in its implementation document along with a justification for the inconsistent practices. Accordingly, pursuant to
section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission directs the ERO to develop a
modification to the Reliability Standard pursuant to its Reliability Standards development process requiring transmission
service providers to include in their implementation documents any inconsistent modeling practices along with a
justification for such inconsistencies.

Consideration of Directive
The ad hoc group considered the directive of requiring TSPs to include in their implementation documents any inconsistent
modeling practice along with a justification. Within their documentation and in response to questions, the TSP or TOP will
provide information regarding their modeling and if the modeling practices are consistent throughout time. As identified in
Requirement R5 of the pro forma standard, an entity can request a rationale if there is a change in a modeling practice
across time frames. It does not impair another entity to use the information contained within the TSP’s ATCID. Because the
ad hoc group states this directive is not reliability focused as noted above, the ad hoc group proposes that this directive
may be considered by NAESB or another standards body through its standards development process. Removing a
requirement or not directly responding to a directive that has little to no impact to reliability is also consistent with the
Commission’s Paragraph 81 initiative.

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S-Ref 10216
200. With regard to Midwest ISO’s concern, while the terms “assumptions” and “no more limiting” as used in Requirements
R6 and R7 could benefit from further granularity, we find these Requirements to be sufficiently clear for purposes of
compliance. Likewise, with regard to Entegra’s concern, we agree that transmission service providers should use data and
assumptions for their available transfer capability or available flowgate capability and total transfer capability or total
flowgate capability calculations that are consistent with those used in the planning of operations and system expansion.
Under Requirements R6 and R7, transmission service providers and transmission operators must not overstate assumptions
that are used in planning of operations. We believe these requirements are sufficiently clear as written. Nonetheless, we
encourage the ERO to consider Midwest ISO’s and Entegra’s comments when developing other modifications to the MOD
Reliability Standards pursuant to the ERO’s Reliability Standards development procedure.

Consideration of Directive
This directive may be withdrawn subject to the FERC NOPR issued June 20, 2013. In the NOPR, FERC reasoned that this
paragraph is not a directive to change or modify a standard.
The ad hoc group considered the directive that the terms “assumptions” and “no more limiting” could benefit from further
granularity. The TOP is potentially responsible for the TTC, TFC, and TRM calculations and must clearly communicate how
those calculations are done both in the methodology and in response to requests for clarification. The reliability need is
communication of the method so that other parties can understand how the calculation is being performed. There is no
reliability benefit in requiring the TOP to explain how its TTC or TFC uses consistent or less limiting assumptions than their
operations planning. Because the ad hoc group states this directive is not reliability focused as noted above, the ad hoc
group proposes that this directive may be considered by NAESB or another standards body through its standards
development process as there may be important commercial aspects to ensure that the TSP is not being overly conservative
in their determination of ATC. Removing a requirement or not directly responding to a directive that has little to no impact
to reliability is also consistent with the Commission’s Paragraph 81 initiative.

S-Ref 10217
220. We agree with NERC that a transmission service provider should consider any information provided in establishing an
appropriate level of capacity benefit margin. Similarly, we agree with the Georgia Companies that all relevant information
should be considered in establishing an appropriate level of capacity benefit margin, including information provided by
customers. However, in determining the appropriate generation capacity import requirement as part of the sum of capacity
benefit margin to be requested from the transmission service provider, it would not be appropriate for a load-serving entity
or resource planner to rely exclusively on a reserve margin or adequacy requirement established by an entity that is not
subject to this Standard. Thus, we hereby adopt the NOPR proposal to direct the ERO to develop a modification to
Requirements R3.1 and R.4.1 of MOD-004-1 to require load-serving entities and resource planners to determine
generation capability import requirements by reference to one or more relevant studies (loss of load expectation, loss of
load probability or deterministic risk analysis) and applicable reserve margin or resource adequacy requirements, as
relevant. Such a modification should ensure that a transmission service provider has adequate information to establish the
appropriate level of capacity benefit margin.

Consideration of Directive
The ad hoc group considered the directive to require LSEs and RPs to determination generation capability import
requirements by reference to one or more relevant studies. The method of calculating CBM is determined by the TSP in
keeping with any FERC or other standards bodies’ guidelines and must be described in the TSP’s CBMID. Placing a
requirement on LSEs and RPs to provide certain information to that CBM process does not improve the quality of
communication between the TSP and the TOP (or others). Also, the applicability section of the pro forma standard does not
apply to LSEs or RPs, as it is the TSPs responsibility to prepare, keep current, and implement its CBMID. Because the ad hoc
group states this directive is not reliability focused as noted above, the ad hoc group proposes that this directive may be
considered by NAESB or another standards body through its standards development process. Removing a requirement or
not directly responding to a directive that has little to no impact to reliability is also consistent with the Commission’s
Paragraph 81 initiative.

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Outstanding FERC Directives

S-Ref 10218
222. We agree with the Midwest ISO that ISOs, RTOs, and other entities with a wide view of system reliability needs should
be able to provide input into determining the total amount of capacity benefit margin required to preserve the reliability of
the system. However, Requirements R1.3 and R7 already make clear that determinations of need for generation capability
import requirement made by a load serving entity or resource planner are not final. Further, the third bullet of
Requirements R5 and R6 explicitly lists reserve margin or resource adequacy requirements established by RTOs and ISOs
among the factors to be considered in establishing capacity benefit margin values for available transfer capability paths or
flowgates used in available transfer capability or available flowgate capability calculations. In fact, it is for this reason that
we uphold the NOPR proposal. Therefore, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our regulations,
the Commission directs the ERO to modify MOD-004-1 to clarify the term “manage” in Requirement R1.3. This
modification should ensure that the Reliability Standard clarify how the transmission service provider will manage
situations where the requested use of capacity benefit margin exceeds the capacity benefit margin available.

Consideration of Directive
The ad hoc group considered the directive to clarify the term “manage” in MOD-004-1. The pro forma standard does not
include the prescriptive components and therefore does not contain the term “manage.” Therefore, provided the standard
is approved by industry without the term, it will not be necessary for NERC to clarify this term.

S-Ref 10219
231. The Commission understands sub-requirement R2.2 of MOD-028-1 to mean that, when calculating total transfer
capability for available transfer capability paths, a transmission operator shall use a transmission model that includes
relevant data from reliability coordination areas that are not adjacent. While we believe that the provision is reasonably
clear, the Commission agrees that the term “and beyond” could be better explained. Accordingly, pursuant to section
215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission directs the ERO to develop a modification subrequirement R2.2 pursuant to its Reliability Standards development process to clarify the phrase “adjacent and beyond
Reliability Coordination areas.”

Consideration of Directive
This directive may be withdrawn subject to the FERC NOPR issued June 20, 2013. In the NOPR, FERC reasoned that this
paragraph clarifies the Commission’s understanding of the phrase “adjacent and beyond Reliability Coordination area.”
Since the Commission’s understanding of the language is clearly expressed, and the matter has little impact on reliability,
there is no reason to go forward with this directive.
The ad hoc group considered the directive to clarify the phrase “adjacent and beyond Reliability Coordination areas.” The
pro forma standard does not contain the phrase “adjacent and beyond Reliability Coordination areas.” Therefore, provided
the standard is approved by industry without the phrase, it will not be necessary for NERC to clarify this phrase.

S-Ref 10220
234. The Commission believes that, as written, the time frames established in Requirement R5 are just and reasonable
because they balance the need to reliably operate the grid with the burden on transmission operators to recalculate total
transfer capability even when total transfer capability does not often change. Nevertheless, the Commission agrees that a
graduated time frame for reposting could be reasonable in some situations. Accordingly, the ERO should consider this
suggestion when making future modifications to the Reliability Standards.

Consideration of Directive
This directive may be withdrawn subject to the FERC NOPR issued June 20, 2013. In the NOPR, FERC reasoned that this
paragraph is not a directive to change or modify a standard.
The ad hoc group considered the directive of a graduated time frame for reposting of TTC even when TTC does not often
change. Under the new pro forma standard, the time frame within which a value is recalculated and reposted based on an
outage would be addressed by the TOP and the TSP in their methodology. There is no reliability benefit in the pro forma
standard dictating the time frame for an Area Interchange Methodology user to update their TTC based on an outage since
it does not contribute to the quality of communication with the TOP and others. Because the ad hoc group states this
directive is not reliability focused as noted above, the ad hoc group proposes that this directive may be considered by
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Outstanding FERC Directives

NAESB or another standards body through its standards development process. Removing a requirement or not directly
responding to a directive that has little to no impact to reliability is also consistent with the Commission’s Paragraph 81
initiative.

S-Ref 10221
237. The Commission agrees that any distribution factor to be used should be clearly stated in the implementation
document, and that to facilitate consistent and understandable results the distribution factors used in determining total
transfer capability should be applied consistently. Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f)
of our regulations, the Commission directs the ERO to develop a modification to MOD-028-1 pursuant to its Reliability
Standards development process to address these two concerns.

Consideration of Directive
The ad hoc group considered the directive to clearly state any distribution factor used in the implementation document.
The pro forma standard requires disclosure of the TOP’s method of addressing TTC and the TSP’s method of determining
ATC, which will require disclosure of how distribution factors are used, if they are used. Another reliability purpose of the
standard is to allow other TOPs to influence the calculation of TTC and TFC. To address this, the ad hoc group included
requirement part 1.3 in the pro forma standard. This requirement part states that the TTC or TFC methodology for
calculating TTC or TFC shall address reliability-related constraints requested to be included per Requirement R1 and
identified by another TOP are used within a component of the TTC or TFC calculation. Furthermore, the TOP must use a
distribution factor, whether it be OTDP or PTDF of 5% or less when determining if these constraints should be monitored.

S-Ref 10222
246. Puget Sound’s request is reasonable, and insofar as calculating non-firm available transfer capability using
counterschedules as opposed to counterflows achieves substantially equivalent results, using them will not be considered a
violation. However, we do not have enough information to determine that the terms are generally interchangeable in all
circumstances. The ERO should consider Puget Sound’s concerns on this issue when making future modifications to the
Reliability Standards.

Consideration of Directive
This directive may be withdrawn subject to the FERC NOPR issued June 20, 2013. In the NOPR, FERC reasoned that this
paragraph is not a directive to change or modify a standard.
The ad hoc group considered the directive to clarify if the terms counterschedule and counterflow could be generally
interchangeable in all circumstance. This new pro forma standard requires disclosure of the TSP’s method of calculating ATC
and would include their handling of counterflows or counterschedules. The pro forma standard focuses on clear
communication between the TSP and the TOP (and others) on how ATC is calculated, and as such the standard does not
specify the specific components that would go into the ATC calculation including counterflows and counterschedules, thus
avoiding confusion between the two terms.

S-Ref 10223
269. As noted above, the Commission approves the proposal to make these Reliability Standards effective on the first day of
the first calendar quarter that is twelve months beyond the date that the Reliability Standards are approved by all
applicable regulatory authorities. Although MOD-030-2 defines its effective date with reference to the effective date of
MOD-030-1, the Commission finds that this direction is sufficiently clear in the context of the current proceeding. To the
extent necessary, we clarify MOD-030-2 shall become effective on the first day of the first calendar quarter that is twelve
months beyond the date that the Reliability Standards are approved by all applicable regulatory authorities. The
Commission also directs the ERO to make explicit such detail in any future version of this or any other Reliability
Standard.

Consideration of Directive
This directive may be withdrawn subject to the FERC NOPR issued June 20, 2013. In the NOPR, FERC reasoned that this
paragraph is not a directive to change or modify a standard. The ERO has made explicit the effective date in the pro forma
standard.

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Outstanding FERC Directives

S-Ref 10226
304. The Commission believes that the definition of Postback is not fully determinative. NERC should be able to define this
term without reference to the Business Practices, another defined term. Accordingly, the Commission adopts its NOPR
proposal and directs the ERO to develop a modification to the definition of Postback to eliminate the reference to
Business Practices. Although we are sensitive to Puget Sound’s concern that the required Postback component may
increase the recordkeeping burden on some entities, in other regions the component may be critical. We disagree that the
term’s existence assumes that once a reservation is confirmed on a particular point of reservation or point of receipt
combination the impact of the confirmed reservation will always be present in the available transfer capability calculation.
However, we would consider suggestions that would allow entities to comply with the requirements as efficiently as
possible, such as a regional difference through the ERO’s standards development procedure.

Consideration of Directive
The term Postback is not used in the pro forma standard; therefore, provided the standard is approved by industry without
the term, it will not be necessary for NERC to clarify the term by adding this definition to the NERC Glossary of Terms used
in the NERC Reliability Standards.

S-Ref 10227
305. The Commission also adopts its NOPR proposal to direct the ERO to develop a modification to the definition of
Business Practices that would remove the reference to regional reliability organizations and replace it with the term
Regional Entity. We also direct the ERO to develop a definition of the term Regional Entity to be included in the NERC
Glossary.

Consideration of Directive
The term Business Practices is not used in the pro forma standard; therefore, provided the standard is approved by industry
without the term, it will not be necessary for NERC to clarify the term by adding this definition to the NERC Glossary of
Terms used in the NERC Reliability Standards. The ad hoc group also notes that developing a definition to the term Regional
Entity in the NERC Glossary of Terms Used in Reliability Standards would be another initiative by the ERO and not in focus
for the MOD A informal ad hoc group.

S-Ref 10229
306. We agree with SMUD and Salt River that the definition of “ATC Path” should not limit a transmission provider’s
flexibility to treat multiple parallel interconnections between balancing authorities as a single path, and that available
transfer capability paths may comprise multiple, parallel interconnections between Balancing Authorities when such
treatment is appropriate to maintain reliability. We also agree that the definition should not reference the Commission’s
regulations. The Commission’s regulations are not applicable to all registered entities and are subject to change. We
therefore direct the ERO to develop a modification to the definition of “ATC Path” that does not reference the
Commission’s regulations.

Consideration of Directive
The term ATC Path is not used in the pro forma standard; therefore, provided the standard is approved by industry without
the term, it will not be necessary for NERC to clarify the term by adding this definition to the NERC Glossary of Terms used
in the NERC Reliability Standards.

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Conclusion
The informal development for the MOD A initiative provided key discussions with regard to the reliability impacts of the
existing MOD A NERC Reliability Standards. There were issues identified early in the process that were able to be discussed
at varying lengths to come to the conclusion where the ad hoc group landed in consolidating the existing six standards into
one pro forma standard. The pro forma standard covers the reliability-related impact of ATC and AFC calculations. The
approach is intended to maintain NERC’s focus on developing and retaining requirements that support the reliable
operation of the BPS.
This white paper serves as further information for the work the informal ad hoc group conducting in considering the
outstanding directives from FERC Order 729, along with the other components of the results-based standards, such as a
risk-based and performance-based standard, along with incorporating the Paragraph 81 initiative.

NERC | MOD A White Paper | July 3, 2013
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Appendix A: Acronyms
This section contains the list of acronyms used throughout the white paper.
Table 1: Acronyms
Acronym

Spelled Out

Acronym

Spelled Out

AFC

Available Flowgate Capability

OTDF

Outage Transfer Distribution Factor

ATC

Available Transfer Capability

PC

Planning Coordinator

ATCID

Available Transfer Capability
Implementation Document

POD

Point of Delivery

BPS

Bulk Power System

POR

Point of Receipt

CBM

Capacity Benefit Margin

PTDF

Power Transfer Distribution Factor

CBMID

Capacity Benefit Margin Implementation
Document

RC

Reliability Coordinator

EEA

Energy Emergency Alert

RP

Resource Planner

ERO

Electric Reliability Organization

RSP

Rated System Path

ETC

Existing Transmission Commitments

SAR

Standards Authorization Request

FERC

Federal Energy Regulatory Commission

SC

Standards Committee

FPA

Federal Power Act

SOL

System Operating Limit

SME

Subject Matter Expert

STE

Short-Term Emergency

GCIR
IROL

Generation Capability Import
Requirement
Interconnection Reliability Operating
Limit

ITC

Incremental Transfer Capability

TFC

Total Flowgate Capability

LSE

Load-Serving Entity

TLR

Transmission Loading Relief

LTE

Long-Term Emergency

TO

Transmission Owner

MW

Megawatt

TOP

Transmission Operator

NAESB

North American Energy Standards Board

TP

Transmission Planner

NERC

North American Electric Reliability
Corporation

TRM

Transmission Reliability Margin

NOPR

Notice of Proposed Rulemaking

TRMID

Transmission Reliability Margin
Implementation Document

OASIS

Open Access Same-Time Information
System

TSP

Transmission Service Provider

TTC

Total Transfer Capability

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Appendix B: Entity Participants
The below entities represent a non-exhaustive list of entities that had personnel that participated in the MOD-A informal
development effort in some manner, which may include one of the following: direct participation on the ad-hoc group,
inclusion on the wider distribution (the “plus” list), attendance at workshops or other technical discussions, participation in
a webinar or teleconference, or by providing feedback to the group through a variety of methods (e.g., email, phone calls,
etc.). Additionally, though not listed here, announcements were distributed to wider NERC distribution lists to provide the
opportunity for entities that were not actively participating to join the effort.
Table 2: Entity Participation in MOD A Informal Development
AECI

Dynegy

MEAG Power

PSEG

WAPA

ALCOA

ERCOT

MidAmerican

Puget Sound

WECC RC

Ameren

FPL

Minnkota Power

REMC

Wisconsin Public Service

APS

GCPUD

MISO

Santee Cooper

Xcel Energy

APSC

GRE Energy

National Grid

SaskPower

ATC

GRU

NIPSCO

SCANA

BC Hydro

GTC

Northwestern Energy

SCE

Regional Entities

Beaches Energy

Hydro Quebec

NSTAR

Seminole Electric

FRCC

BPA

HydroOne Networks

NV Energy

SMUD

MRO

CAISO

Idaho Power

OGE

SNEW

NPCC

CB Power Coop

IMPA

OMPA

Southern Company

RFC

Centerpoint
Energy

ISO-NE

Oncor

SPP RC

SERC

City of Tallahassee

ITC Transmission

OPPD

SRP

SPP

ConEd

JEA

OUC

Sunflower Electric

TRE

Constellation
Energy

KCPL

PacifiCorp

TANC

WECC

CPP

KUA

PGE

TECO

CSU

LADWP

PJM

TEP

Dominion

LCEC

PNM

TID

Duke Energy

Lincoln Electric
System

Portland General Electric

Tristate G&T

Duquesne Light

MAPP

Progress Energy

TVA

Table 3: Presentations and Events
Western Interconnection Compliance Forum
NERC Operating Committee
NATF

NERC News

wesTTrans
MISO Available Flowgate Capability Working
Group

NERC Standards Committee

NERC Planning Committee

NERC Standards and Compliance Workshop

FRCC Transmission Working Group

Florida Transfer Capability Determination Group

SPP Compliance Workshop

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Project 2012-05 Mapping Document

Transition of MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and
MOD-030-2 to MOD-001-2 (the pro forma standard)

Requirement in
Approved Standard
MOD-001-1a R1
MOD-001-1a R2
MOD-001-1a R2.1
MOD-001-1a R2.2
MOD-001-1a R2.3
MOD-001-1a R3
MOD-001-1a R3.1
MOD-001-1a R3.2

Standard: MOD-001-1a – Available Transmission System Capability
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
The pro forma standard requires disclosure of the method used to
Requirement R2
calculate ATC but no longer requires it to be spelled out in its own
Requirement.
The pro forma standard will require disclosure of calculation frequency
Requirement R2
but does not specify the range of required calculations.
Requirement R2
See comments on Requirement R2.
Requirement R2
See comments on Requirement R2.
Requirement R2
See comments on Requirement R2.
The new Requirement R2 picks up the obligation to prepare, keep
Requirement R2
current, and implement the ATCID and have complete information on
how ATC is determined.
This would be included within the ATCID created under Requirement
Requirement R2
R2.
This would be included within the ATCID created under Requirement
Requirement R2
R2.

Project 2012-05 ATC Revisions

Requirement in
Approved Standard
MOD-001-1a R3.2.1
MOD-001-1a R3.2.2
MOD-001-1a R3.3
MOD-001-1a R3.4
MOD-001-1a R3.5
MOD-001-1a R3.6
MOD-001-1a R3.6.1
MOD-001-1a R3.6.2
MOD-001-1a R3.6.3
MOD-001-1a R4
MOD-001-1a R4.1
MOD-001-1a R4.2
MOD-001-1a R4.3
MOD-001-1a R4.4

Standard: MOD-001-1a – Available Transmission System Capability
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
This would be included within the ATCID created under Requirement
Requirements R2 & R5
R2 or if not addressed there (due to not being used) and it may be
addressed under R5 in response to a request for clarification.
This would be included within the ATCID created under Requirement
Requirement R2
R2.
This would be included within the ATCID created under Requirement
Requirement R2
R2.
The identity of the TSPs and TOPs for which it provides data is captured
Component of Requirement R6
when an entity formally requests for that information.
This would be included within the ATCID created under Requirement
Requirement R2
R2.
This would be included within the ATCID created under Requirement
Requirement R2
R2.
This would be included within the ATCID created under Requirement
Requirement R2
R2.
This would be included within the ATCID created under Requirement
Requirement R2
R2.
This would be included within the ATCID created under Requirement
Requirement R2
R2.
Requirement R5 for an ATCID provided upon
formal request.

The Requirement for a TSP to notify entities when a change is made to
its ATCID is an administrative burden. Posting on its company website
or OASIS provides the alert that a change has been made.

2

Project 2012-05 ATC Revisions

Requirement in
Approved Standard
MOD-001-1a R4.5
MOD-001-1a R4.6

Standard: MOD-001-1a – Available Transmission System Capability
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action

MOD-001-1a R5

New Requirement R5 for an ATCID provided
upon formal request.

MOD-001-1a R6

The Requirement has been retired.

MOD-001-1a R7

The Requirement has been retired.

MOD-001-1a R8

The Requirement has been retired.

MOD-001-1a R8.1
MOD-001-1a R8.2
MOD-001-1a R8.3

The Requirement has been retired.
The Requirement has been retired.
The Requirement has been retired.

The Requirement for a TSP to notify entities when a change is made to
its ATCID is an administrative burden. Posting on its company website
or OASIS provides the alert that a change has been made.
Ensuring that ATC, TTC, AFC, and TFC calculations use assumptions no
more limiting then those used in the planning of operations does not
serve a clear reliability goal. The ATCID will have a description of how
ATC, TTC, AFC, or TFC is calculated, with sufficient detail to allow for a
comparison.
Ensuring that ATC, TTC, AFC, and TFC calculations use assumptions no
more limiting then those used in the planning of operations does not
serve a clear reliability goal. The ATCID will have a description of how
ATC, TTC, AFC, or TFC is calculated, with sufficient detail to allow for a
comparison.
The reliability component of ATC is disclosure of an entity’s practice
which is still captured, but not the performance aspect of the ATC
calculations.
See comments on Requirement R8.
See comments on Requirement R8.
See comments on Requirement R8.

3

Project 2012-05 ATC Revisions

Requirement in
Approved Standard

MOD-001-1a R9

MOD-001-1a R9.1
MOD-001-1a R9.1.1
MOD-001-1a R9.1.2
MOD-001-1a R9.1.3
MOD-001-1a R9.2

Requirement in
Approved Standard
MOD-004-1 R1

MOD-004-1 R1.1

MOD-004-1 R1.2

Standard: MOD-001-1a – Available Transmission System Capability
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
Requirement R5 of the pro forma standard requires a TOP or TSP,
within 30 calendar days of receiving a written request, to respond to a
registered entity that demonstrates a reliability need, a written
response to any request for clarification of its ATCID, or, if not publicly
posted, its effective ATCID, CBMID, TRMID, or TTC or TFC methodology.
Requirement R5
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.

Standard: MOD-004-1 – Capacity Benefit Margin
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.

4

Project 2012-05 ATC Revisions

Requirement in
Approved Standard
MOD-004-1 R1.3

MOD-004-1 R2

MOD-004-1 R3

MOD-004-1 R3.1

MOD-004-1 R3.2

MOD-004-1 R4

MOD-004-1 R4.1

MOD-004-1 R4.2

Standard: MOD-004-1 – Capacity Benefit Margin
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.
Also, the new Requirement R3 picks up the obligation to prepare, keep
Requirement part R5.2.2
current, and implement the CBMID and have complete information on
how is determined.
Requirement R3, in that CBM set aside for
The applicability of the pro forma standard has been changed so that
imports into a BAA can be accommodated
the LSE is not an applicable entity within the standard.
in the TSPs CBMID.
Requirement R3, in that the TSP’s CBMID
The applicability of the pro forma standard has been changed so that
can utilize any of the methods specified, but
the LSE is not an applicable entity within the standard.
is no longer limited to just what is listed.
Requirement R3, in that the TSP’s CBMID
The applicability of the pro forma standard has been changed so that
can utilize any of the methods specified, but
the LSE is not an applicable entity within the standard.
is no longer limited to just what is listed.
Requirement R3, in that CBM set aside for
The applicability of the pro forma standard has been changed so that
imports into a BAA can be accommodated
the RP is not an applicable entity within the standard.
in the TSP’s CBMID.
Requirement R3, in that the TSP’s CBMID
The applicability of the pro forma standard has been changed so that
can utilize any of the methods specified, but
the RP is not an applicable entity within the standard.
is no longer limited to just what is listed.
Requirement R3, in that the TSP’s CBMID
The applicability of the pro forma standard has been changed so that
can utilize any of the methods specified, but
the RP is not an applicable entity within the standard.
is no longer limited to just what is listed.

5

Project 2012-05 ATC Revisions

Requirement in
Approved Standard
MOD-004-1 R5

MOD-004-1 R5.1

MOD-004-1 R5.2
MOD-004-1 R6
MOD-004-1 R6.1
MOD-004-1 R6.2
MOD-004-1 R7
MOD-004-1 R8
MOD-004-1 R9
MOD-004-1 R9.1

Standard: MOD-004-1 – Capacity Benefit Margin
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not specify
what must be included or how it is calculated.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not specify
what must be included or how it is calculated.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not specify
what must be included or how it is calculated.
The applicability of the pro forma standard has been changed so that
The Requirement has been retired.
the TP is not an applicable entity within the standard.
The applicability of the pro forma standard has been changed so that
The Requirement has been retired.
the TP is not an applicable entity within the standard.
The applicability of the pro forma standard has been changed so that
The Requirement has been retired.
the TP is not an applicable entity within the standard.
The pro forma standard will require entities that utilize a CBM to make
Requirement part R5.2.2
available its CBMID to all registered entities that have a reliability need.
The applicability of the pro forma has been changed so that the TP is
The Requirement has been retired.
not an applicable entity within the standard.
The new Requirement R6 requires the sharing of data used in ATC
Requirement R6
calculations which would include the data used in CBM calculations.
The new Requirement R6 requires the sharing of data used in ATC
Requirement R6
calculations which would include the data used in CBM calculations.

6

Project 2012-05 ATC Revisions

Requirement in
Approved Standard
MOD-004-1 R9.2
MOD-004-1 R10
MOD-004-1 R11

MOD-004-1 R12

MOD-004-1 R12.1

MOD-004-1 R12.2

MOD-004-1 R12.3

Requirement in
Approved Standard
MOD-008-1 R1

Standard: MOD-004-1 – Capacity Benefit Margin
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
The new Requirement R6 requires the sharing of data used in ATC
Requirement R6
calculations which would include the data used in CBM calculations.
The applicability of the pro forma standard has been changed so that
The Requirement has been retired.
the LSE or BA is not applicable entities within the standard.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.
The pro forma standard will require entities that utilize a CBM to
Requirement R3
prepare, keep current and implement a CBMID but does not dictate
what must be included or how it is calculated.
Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
Requirement R4
Requirement R4 requires a TRMID

7

Project 2012-05 ATC Revisions

Requirement in
Approved Standard
MOD-008-1 R1.1

MOD-008-1 R1.2
MOD-008-1 R1.3
MOD-008-1 R1.3.1
MOD-008-1 R1.3.2
MOD-008-1 R1.3.3

MOD-008-1 R2

MOD-008-1 R3
MOD-008-1 R4

Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
Requirement R4 requires a TRMID that describes how the value was
developed; requiring that the definition fit within a defined list of
Requirement R4
components, as required by MOD-008-1 R1.1, does not aid the
reliability goal of disclosure.
Requirement R4 requires a TRMID that will describe how a calculated
Requirement R4
value is used in the ATC calculation.
Requirement R4 requires a TRMID that will describe how a calculated
Requirement R4
value is used in the ATC calculation.
Requirement R4 requires a TRMID that will describe how a calculated
Requirement R4
value is used in the ATC calculation.
Requirement R4 requires a TRMID that will describe how a calculated
Requirement R4
value is used in the ATC calculation.
Requirement R4 requires a TRMID that will describe how a calculated
Requirement R4
value is used in the ATC calculation.
Requirement R4 requires a TRMID that describes how a calculated
value is determined without being prescriptive. Prescribing that the
Requirement R4
value must come from a predefined list of uncertainties or that the
value does not double count with CBM does not serve the reliability
goal of disclosure of practice.
Requirement R5 requires disclosure of TRMID upon request if not
Requirement R5
already posted on OASIS or similar site.
Requirement R4 requires a TRMID that includes the frequency of
Requirement R4
updating; setting an arbitrary date to recalculate TRM does not
contribute to the reliability goal of disclosure.

8

Project 2012-05 ATC Revisions

Requirement in
Approved Standard
MOD-008-1 R5

Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Transitions to the below Requirement in
Description and Change Justification
New Standard or Other Action
Requirements R2 and R4, the ATCID and TRMID respectively, would
contain information on how the value is shared and on what frequency.
Requirements R2 & R4
Setting an arbitrary frequency is unnecessary to meet the reliability
goal of disclosure.

Standard: MOD-028-1 – Area Interchange Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-028-1 R1

Requirements R1 & R2

MOD-028-1 R1.1

Requirements R1 & R2

MOD-028-1 R1.2

Requirements R1 & R2

MOD-028-1 R1.3

Requirements R1 & R2

MOD-028-1 R1.4

Requirements R1 & R2

MOD-028-1 R1.5

Requirements R1 & R2

Description and Change Justification
Requirement R1 requires disclosure by the TOP of how TTC is
determined. Requirement R2 requires disclosure by the TSP of how ATC
is determined which would include any parts of the TTC development
not covered by a TOP under R1.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of this practice.

9

Project 2012-05 ATC Revisions

Standard: MOD-028-1 – Area Interchange Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-028-1 R1.5.1

Requirements R1 & R2

MOD-028-1 R1.5.2

Requirements R1 & R2

MOD-028-1 R1.5.3

Requirements R1 & R2

MOD-028-1 R1.5.4

Requirements R1 & R2

MOD-028-1 R2

Requirements R1 & R2

MOD-028-1 R2.1

Requirements R1 & R2

MOD-028-1 R2.2

Requirements R1 & R2

MOD-028-1 R2.3

Requirements R1 & R2

MOD-028-1 R3

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of this practice.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice. In addition, R1 requires the TOP to use
the defined facility ratings and SOL's, as appropriate, to determine the
TTC value.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.

10

Project 2012-05 ATC Revisions

Standard: MOD-028-1 – Area Interchange Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-028-1 R3.1

Requirements R1 & R2

MOD-028-1 R3.1.1

Requirements R1 & R2

MOD-028-1 R3.1.2

Requirements R1 & R2

MOD-028-1 R3.1.2

Requirements R1 & R2

MOD-028-1 R3.2

Requirements R1 & R2

MOD-028-1 R3.2.1

Requirements R1 & R2

MOD-028-1 R3.2.2

Requirements R1 & R2

MOD-028-1 R3.2.2

Requirements R1 & R2

Description and Change Justification
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice. In addition, R1 requires the TOP to
specifically disclose their use of expected outages and other topology
changes.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice. In addition R1 requires the TOP to
specifically disclose their use load forecasts
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice. In addition, R1 requires the TOP to
specifically disclose their dispatch assumptions.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice. In addition, R1 requires the TOP to
specifically disclose their use of expected outages and other topology
changes.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice. In addition R1 requires the TOP to
specifically disclose their use load forecasts
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice. In addition, R1 requires the TOP to
specifically disclose their dispatch assumptions.

11

Project 2012-05 ATC Revisions

Standard: MOD-028-1 – Area Interchange Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-028-1 R4

Requirements R1 & R2

MOD-028-1 R4.1

Requirements R1 & R2

MOD-028-1 R4.2

Requirements R1 & R2

MOD-028-1 R4.3

Requirements R1 & R2

MOD-028-1 R5

Requirements R1 & R2

MOD-028-1 R5.1

Requirements R1 & R2

MOD-028-1 R5.2

Requirements R1 & R2

Description and Change Justification
This requirement serves no direct purpose other than as a bridge to the
sub requirements below.
Requirements R1 and R2 set this obligation upon the TOP and TSP,
respectively.
Requirements R1 and R2 require disclosure of practice, which is the
reliability need for this requirement. Verification that a contract is being
followed is primarily a commercial issue and not a NERC Reliability
issue.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC, which is not necessary within a NERC requirement to
protect reliability.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
calculation will be discussed within the ATCID and driven by either
reliability or market needs, whichever provides for a tighter time frame.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
calculation will be discussed within the ATCID and driven by either
reliability or market needs, whichever provides for a tighter time frame.

12

Project 2012-05 ATC Revisions

Standard: MOD-028-1 – Area Interchange Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-028-1 R5.3

Requirements R1 & R2

MOD-028-1 R6

Requirements R1 & R2

MOD-028-1 R6.1

Requirements R1 & R2

MOD-028-1 R6.2

Requirements R1 & R2

MOD-028-1 R6.3

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
calculation will be discussed within the ATCID and driven by either
reliability or market needs, whichever provides for a tighter time frame.
This requirement serves no direct purpose other than as a bridge to the
sub requirements below.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.

13

Project 2012-05 ATC Revisions

Standard: MOD-028-1 – Area Interchange Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-028-1 R6.4

Requirements R1 & R2

MOD-028-1 R7

Requirement R1

MOD-028-1 R7.1

Requirement R1

MOD-028-1 R7.2

Requirement R1

MOD-028-1 R8

Requirement R2

Description and Change Justification
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.
This requirement serves no direct purpose other than as a bridge to the
sub requirements below.
Requirement R1 of the pro forma standard requires disclosure of the
frequency of update, which is the reliability need this requirement
addresses. The frequency of disclosure is set by agreement with the TSP
or other factors, and there is no reliability benefit in setting an arbitrary
frequency of providing the value.
Requirement R1 of the pro forma standard requires disclosure of the
frequency of update, which is the reliability need this requirement
addresses. The frequency of disclosure is set by agreement with the TSP
or other factors, and there is no reliability benefit in setting an arbitrary
frequency of providing the value.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which does not contribute to the reliability need of disclosure of
the TSP's process.

14

Project 2012-05 ATC Revisions

Standard: MOD-028-1 – Area Interchange Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-028-1 R9

Requirement R2

MOD-028-1 R10

Requirement R2

MOD-028-1 R11

Requirement R2

Standard: MOD-029-1a – Rated System Path Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-029-1a R1

Requirements R1 & R2

Description and Change Justification
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which does not contribute to the reliability need of disclosure of
the TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ATC, which does not contribute to the reliability need of disclosure of
the TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, specifically documentation of their process. The
remainder of the material in the requirement provides instructions on
determining ATC, which do not contribute to the reliability need of
disclosure of the TSP's process.

Description and Change Justification
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.

15

Project 2012-05 ATC Revisions

Standard: MOD-029-1a – Rated System Path Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-029-1a R1.1

Requirements R1 & R2

MOD-029-1a R1.1.1

Requirements R1 & R2

MOD-029-1a R1.1.1.1

Requirements R1 & R2

MOD-029-1a R1.1.1.2

Requirements R1 & R2

MOD-029-1a R1.1.1.3

Requirements R1 & R2

MOD-029-1a R1.1.2

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.

16

Project 2012-05 ATC Revisions

Standard: MOD-029-1a – Rated System Path Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-029-1a R1.1.3

Requirements R1 & R2

MOD-029-1a R1.1.4

Requirements R1 & R2

MOD-029-1a R1.1.5

Requirements R1 & R2

MOD-029-1a R1.1.6

Requirements R1 & R2

MOD-029-1a R1.1.7

Requirements R1 & R2

MOD-029-1a R1.1.8

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.

17

Project 2012-05 ATC Revisions

Standard: MOD-029-1a – Rated System Path Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-029-1a R1.1.9

Requirements R1 & R2

MOD-029-1a R1.1.10

Requirements R1 & R2

MOD-029-1a R2

Requirements R1 & R2

MOD-029-1a R2.1

Requirements R1 & R2

MOD-029-1a R2.1.1

Requirements R1 & R2

MOD-029-1a R2.1.2

Requirements R1 & R2

MOD-029-1a R2.1.3

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirement R1 specifically requires the TOP to respect transmission
element ratings, R1 and R2 requires disclosure of the TOP and TSP's
practices in this regard.
Requirement R1 specifically requires the TOP to respect these limits
and system operating limits.
Requirement R1 specifically requires the TOP to respect these facility,
voltage, stability limits, and system operating limits, which should
prevent a condition that would result in uncontrolled separation.

18

Project 2012-05 ATC Revisions

Standard: MOD-029-1a – Rated System Path Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-029-1a R2.2

Requirements R1 & R2

MOD-029-1a R2.3

Requirements R1 & R2

MOD-029-1a R2.4

Requirements R1 & R2

MOD-029-1a R2.5

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining TTC, using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.

19

Project 2012-05 ATC Revisions

Standard: MOD-029-1a – Rated System Path Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-029-1a R2.6

Requirements R1 & R2

MOD-029-1a R2.7

Requirements R1 & R2

MOD-029-1a R2.8

Requirements R1 & R2

MOD-029-1a R3

Requirements R1 & R2

MOD-029-1a R4

Requirement R1

Description and Change Justification
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirements R1 and R2 address this need by requiring a methodology,
and in the effort to demonstrate that the methodology was followed
the necessary reports will be developed.
Requirement R1 requires that SOL limits be respected in the
determination of TTC. Requirement R2 requires disclosure of practices
for determining ATC.
Requirement R1 of the pro forma standard requires disclosure of the
frequency of update, which is the reliability need this requirement
addresses. The frequency of disclosure is set by agreement with the TSP
considering individual facts and circumstances, and there is no
reliability benefit in setting an arbitrary frequency of providing the
value.

20

Project 2012-05 ATC Revisions

Standard: MOD-029-1a – Rated System Path Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-029-1a R5

Requirement R2

MOD-029-1a R6

Requirement R2

MOD-029-1a R7

Requirement R2

MOD-029-1a R8

Requirement R2

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

Description and Change Justification
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which does not contribute to the reliability need of disclosure of
the TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which does not contribute to the reliability need of disclosure of
the TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which does not contribute to the reliability need of disclosure of
the TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which does not contribute to the reliability need of disclosure of
the TSP's process.

Description and Change Justification

21

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-030-2 R1

Requirements R1 & R2

MOD-030-2 R1.1

Requirement R1

MOD-030-2 R1.2

Requirements R1 & R2

MOD-030-2 R1.2.1

Requirements R1 & R2

MOD-030-2 R1.2.2

Requirements R1 & R2

MOD-030-2 R1.2.3

Requirements R1 & R2

MOD-030-2 R1.2.4

Requirements R1 & R2

MOD-030-2 R2.1

Requirements R1 & R2

MOD-030-2 R2.1.1

Requirements R1 & R2

Description and Change Justification
Requirement R1 requires disclosure by the TOP of how TTC is
determined. Requirement R2 requires disclosure by the TSP of how ATC
is determined which would include any parts of the TTC development
not covered by a TOP under R1.
Requirement R1 requires that limits and SOL's be respected and
disclosure of how those limits and SOL's aid in the determination of
TTC.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively, of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively, of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively, of this practice.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively, of this practice.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.

22

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-030-2 R2.1.1.1

Requirements R1 & R2

MOD-030-2 R2.1.1.2

Requirements R1 & R2

MOD-030-2 R2.1.1.3

Requirements R1 & R2

MOD-030-2 R2.1.2

Requirements R1 & R2

MOD-030-2 R2.1.2.1

Requirements R1 & R2

MOD-030-2 R2.1.2.2

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.

23

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-030-2 R2.1.2.3

Requirements R1 & R2

MOD-030-2 R2.1.3

Requirements R1 & R2

MOD-030-2 R2.1.4

Requirement R1

MOD-030-2 R2.1.4.1

Requirements R1 & R2

MOD-030-2 R2.1.4.2

Requirements R1 & R2

MOD-030-2 R2.2

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirement R1 addresses the inclusion of constraints identified by
another party.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.

24

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-030-2 R2.3

Requirements R1 & R2

MOD-030-2 R2.4

Requirements R1 & R2

MOD-030-2 R2.5

Requirements R1 & R2

MOD-030-2 R2.5.1

Requirement R1

MOD-030-2 R2.6

Requirement R1

Description and Change Justification
Requirements R1 and R2 require disclosure by the TOP and TSP,
respectively, of their practice that meets the reliability need of this
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirement R1 requires that System Operating Limits, Voltage, and
Stability Limits be respected in the determination of TTC.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
calculation will be discussed within the ATCID and driven by either
reliability or market needs whichever provides for a tighter time frame.
Requirement R1 of the pro forma standard requires disclosure of the
frequency of update, which is the reliability need this requirement
addresses. The frequency of disclosure is set by agreement with the TSP
considering the individual facts and circumstances, and there is no
reliability benefit in setting an arbitrary frequency of providing the
value.
Requirement R1 of the pro forma standard requires disclosure of the
frequency of update, which is the reliability need this requirement
addresses. The frequency of disclosure is set by agreement with the TSP
considering the individual facts and circumstances, and there is no
reliability benefit in setting an arbitrary frequency of providing the
value.

25

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R3

Requirements R1 &R2

MOD-030-2 R3.1

Requirement R1

MOD-030-2 R3.2

Requirements R1 &R2

Description and Change Justification
Requirements R1 and R2 require disclosure of the process for
determining TTC or TFC and other values that lead to the final ATC and
AFC values, which serves the reliability purpose of disclosing the
practices of the TSP in determining ATC and AFC along with its affiliated
values. Additional instructions specifying the content of models to be
provided between the TOP and TSP is best addressed between the
entities and in their ATCID and TTC methodology; it does not serve a
reliability purpose in the standard.
Requirements R1 and R2 require disclosure of the process for
determining TTC or TFC and other values that lead to the final ATC and
AFC values, which serves the reliability purpose of disclosing the
practices of the TSP in determining ATC and AFC along with its affiliated
values. Additional instructions specifying the content of models to be
provided between the TOP and TSP is best addressed between the
entities and in their ATCID and TTC methodology; it does not serve a
reliability purpose in the standard.
Requirements R1 and R2 require disclosure of the process for
determining TTC or TFC and other values that lead to the final ATC and
AFC values. Providing instructions on who is to build a model and where
it is to be delivered does not contribute to reliability need of
determining reliable TTC or TFC's and disclosure of process.

26

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R3.3

Requirement R1

MOD-030-2 R3.4

Requirements R1 & R2

MOD-030-2 R3.5

Requirements R1 & R2

Description and Change Justification
Requirement R1 of the pro forma standard requires disclosure of the
frequency of update, which is the reliability need this requirement
addresses. The frequency of disclosure is set by agreement with the TSP
considering other factors, and there is no reliability benefit in setting an
arbitrary frequency of providing the value.
Requirements R1 and R2 require disclosure of the process for
determining TTC or TFC and other values that lead to the final ATC and
AFC values, which serves the reliability purpose of disclosing the
practices of the TSP in determining ATC and AFC along with its affiliated
values. Additional instructions specifying the content of models to be
provided between the TOP and TSP is best addressed between the
entities and in their ATCID and TTC methodology; it does not serve a
reliability purpose in the standard.
Requirements R1 and R2 require disclosure of the process for
determining TTC or TFC and other values that lead to the final ATC and
AFC values, which serves the reliability purpose of disclosing the
practices of the TSP in determining ATC and AFC along with its affiliated
values. Additional instructions specifying the content of models to be
provided between the TOP and TSP is best addressed between the
entities and in their ATCID and TTC methodology; it does not serve a
reliability purpose in the standard.

27

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R4

Requirements R1 & R2

MOD-030-2 R5

Requirements R1 & R2

MOD-030-2 R5.1

Requirements R1 & R2

MOD-030-2 R5.2

Requirements R1 & R2

Description and Change Justification
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP respectively, including
documentation of their process and the reliability points addressed in
Requirement R1. The remainder of the material in the requirement
provides instructions on determining AFC using a particular flow gate
method, which as a standard requirement does not address a reliability
need.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining AFC using a particular flow gate method,
which as a standard requirement does not address a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP respectively, including
documentation of their process and the reliability points addressed in
R1. The remainder of the material in the requirement provides
instructions on determining AFC using a particular flow gate method,
which as a standard requirement does not address a reliability need.

28

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R5.3

Requirements R1 & R2

MOD-030-2 R6

Requirements R1 & R2

MOD-030-2 R6.1

Requirement R2

MOD-030-2 R6.1.1

Requirement R2

MOD-030-2 R6.1.2

Requirement R2

Description and Change Justification
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP respectively, including
documentation of their process and the reliability points addressed in
Requirement R1. The remainder of the material in the requirement
provides instructions on determining AFC using a particular flow gate
method, which as a standard requirement does not address a reliability
need.
This requirement serves no direct purpose other than as a bridge to the
sub-requirements below.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.

29

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R6.2

Requirement R2

MOD-030-2 R6.2.1

Requirement R2

MOD-030-2 R6.2.2

Requirement R2

MOD-030-2 R6.3

Requirement R2

Description and Change Justification
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.

30

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R6.4

Requirement R2

MOD-030-2 R6.5

Requirement R2

MOD-030-2 R6.6

Requirement R2

MOD-030-2 R6.7

Requirement R2

Description and Change Justification
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.

31

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R7

Requirement R2

MOD-030-2 R7.1

Requirement R2

MOD-030-2 R7.2

Requirement R2

MOD-030-2 R7.3

Requirement R2

Description and Change Justification
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.

32

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R7.4

Requirement R2

MOD-030-2 R7.5

Requirement R2

MOD-030-2 R7.6

Requirement R2

MOD-030-2 R7.7

Requirement R2

Description and Change Justification
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ETC, which do not contribute to the reliability need of disclosure of the
TSP's process.

33

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

MOD-030-2 R8

Requirement R2

MOD-030-2 R9

Requirement R2

MOD-030-2 R10

Requirement R2

MOD-030-2 R10.1

Requirement R2

MOD-030-2 R10.2

Requirement R2

Description and Change Justification
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
AFC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
AFC, which do not contribute to the reliability need of disclosure of the
TSP's process.
Requirement R2 of the pro forma standard requires an ATCID that,
among other things, would describe the frequency of calculation and
updates. Specifying an arbitrary period does not serve the reliability
purpose of disclosure of the TSP's practices.
Requirement R2 of the pro forma standard requires an ATCID that,
among other things, would describe the frequency of calculation and
updates. Specifying an arbitrary period does not serve the reliability
purpose of disclosure of the TSP's practices.
Requirement R2 of the pro forma standard requires an ATCID that,
among other things, would describe the frequency of calculation and
updates. Specifying an arbitrary period does not serve the reliability
purpose of disclosure of the TSP's practices.

34

Project 2012-05 ATC Revisions

Standard: MOD-030-2 – Flowgate Methodology
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
MOD-030-2 R10.3

Requirement R2

MOD-030-2 R11

Requirement R2

Description and Change Justification
Requirement R2 of the pro forma standard requires an ATCID that,
among other things, would describe the frequency of calculation and
updates. Specifying an arbitrary period does not serve the reliability
purpose of disclosure of the TSP's practices.
Requirement R2 maintains the reliability portion of these requirements
upon the TSP, including documentation of their process. The remainder
of the material in the requirement provides instructions on determining
ATC, which do not contribute to the reliability need of disclosure of the
TSP's process.

New Requirements not found in existing MOD standards
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action

Description and Change Justification

R1 (Part)

The existing standards only cover the calculation of TTC or TFC if it is
done to support an ATC or AFC calculation. The proposed standard R1
also incorporates any TTC or TFC calculation done at the request of the
RC or by the TOP for operational purposes, even if not used to
determine ATC or AFC.

New Standard

35

Compliance Operations
Draft Reliability Standard Compliance Guidance for MOD-001-2
June 14, 2013
Introduction

The NERC Compliance department (Compliance) worked with the MOD A informal ad hoc group in a
review of pro forma standard MOD-001-2. The purpose of the review is to discuss the requirements of the
pro forma standard to obtain an understanding of its intended purpose and necessary evidence to
support compliance. The purpose of this document is to address specific questions posed by the MOD A
group and Compliance in order to aid the drafting of the requirements and provide a level of
understanding regarding evidentiary support necessary to demonstrate compliance.
While all testing requires levels of auditor judgment, participating in these reviews allows Compliance to
develop training and approaches to support a high level of consistency in audits conducted by the
Regional Entities. However, this document makes no assessment as to the enforceability of the standard.
The following questions will both assist the MOD A group in further refining the standard and be used to
aid in auditor training.
MOD A MOD-001-2 Questions

Question 1
In the Requirements are the attributes to ‘keep current’ and ‘implement’ sufficiently defined?
Compliance Response to Question 1
The terms ‘keep current’ and ‘implement’ provide for a broad level of auditor judgment. Compliance
recommends that the MOD A informal ad hoc group either consider making the requirement time-bound
(such as every 12-months) or requiring the the registered entity to document in their processes or
procedures the frequency of review (with a not to exceed). Further, the pro forma standard should
describe what constitutes implementation.
Conclusion

In general, Compliance finds the pro forma standard provides a reasonable level of guidance for
Compliance Auditors to conduct audits in a consistant manner. The standard establishes timelines, data
requirements, and ownership of specific actions. Further, the standard provides reasonable guidance to
develop training for Compliance Auditors to execute their reviews. However, Compliance does
recommend the MOD A group address the items noted in the response to the question.
Following final approval of the Reliability Standard, Compliance will develop the final Reliability Standards
Auditor Worksheet (RSAW) and associated training.

Proposed Timeline for the
Project 2012-05 Standard Drafting Team (SDT)
Anticipated Date

Location

Event

11-Jul-13

-

SC Authorizes SAR and Pro Forma Standard for Posting

11-Jul-13

Conduct Nominations for Project 2012-05 SDT

11-Jul-13

-

Post SAR and Pro Forma Standard
for 45-Day Comment Period

15-Aug-13

-

Conduct Ballot

25-Aug-13

-

45-Day Comment Period and Ballot Closes

August 26-30, 2013

TBD

MOD A Standard Drafting Team Face to Face Meeting to
Respond to Initial Comments and Make Possible Revisions

15-Sep-13

-

Conduct Final Ballot

7-Nov-13

-

NERC Board of Trustees Adoption

31-Dec-13

-

NERC Files Petition with the Applicable Governmental
Authorities

Unofficial Nomination Form
Project 2012-05 ATC Revisions
Standard Drafting Team
Please return this form as soon as possible. If you have any questions, please contact Ryan Stewart at
[email protected].
By submitting the following information, you are indicating your willingness and agreement to actively
participate in the Standard Drafting Team (SDT) meetings if appointed to the SDT by the Standards
Committee. This means that if you are appointed to the SDT, you are expected to attend all (or at least
the vast majority) of the face-to-face SDT meetings as well as participate in all the SDT meetings held via
conference calls, and failure to do so shall result in your removal from the SDT.
Project 2012-05 ATC Revisions

The purpose of this project is: (1) to ensure the reliable calculation of Total Flowgate Capability (TFC)
and Total Transfer Capability (TTC) values when those values are used by a Transmission Service
Provider to calculate Available Flowgate Capability (AFC) or Available Transfer Capability (ATC) or used
by a Reliability Coordinator; (2) to require disclosure of how TFC, TTC, Capacity Benefit Margin (CBM),
and Transmission Reliability Margin (TRM) values are calculated for entities with a reliability need for
the information; and (3) to require the sharing of data with other entities with a reliability need for
the AFC, ATC, TFC, TTC, CBM, or TRM values.
We are seeking three individuals who have experience and expertise in the aforementioned areas. If
possible, we would like to add a member from Canada. We are also seeking a lawyer to participate on
the team.
Experience with developing standards inside or outside (e.g., IEEE, NAESB, ANSI, etc.) of the NERC process
is beneficial, but is not required, and should be highlighted in the information submitted if applicable.
Name:
Organization:
Address:

Telephone:
E-mail:

Please briefly describe your experience and qualifications to serve on the requested Standard
Drafting Team:

If you are currently a member of any NERC drafting team, please list each team here:
Not currently on any active SAR or standard drafting team.
Currently a member of the following SAR or standard drafting team(s):
If you previously worked on any NERC drafting team please identify the team(s):
No prior NERC SAR or standard drafting team.
Prior experience on the following team(s):
Select each NERC Region in which you have experience relevant to the Project for which you are
volunteering:
ERCOT
FRCC
MRO

NPCC
RFC
SERC

SPP
WECC
NA – Not Applicable

Select each Industry Segment that you represent:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, and Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations and Regional Entities
NA – Not Applicable

Unofficial Nomination Form
Project 2012-05 ATC Revisions Standard Drafting Team

2

Select each Function1 in which you have current or prior expertise:
Balancing Authority
Compliance Enforcement Authority
Distribution Provider
Generator Operator
Generator Owner
Interchange Authority
Load-serving Entity
Market Operator
Planning Coordinator

Transmission Operator
Transmission Owner
Transmission Planner
Transmission Service Provider
Purchasing-selling Entity
Reliability Coordinator
Reliability Assurer
Resource Planner

Provide the names and contact information for two references who could attest to your technical
qualifications and your ability to work well in a group:

1

Name:

Telephone:

Organization:

E-mail:

Name:

Telephone:

Organization:

E-mail:

These functions are defined in the NERC Functional Model, which is available on the NERC web site.

Unofficial Nomination Form
Project 2012-05 ATC Revisions Standard Drafting Team

3

Standards Announcement
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Ballot and Non-Binding Poll now open through August 26, 2013
Now Available

A ballot for MOD-001-2 and non-binding poll of the associated Violation Risk Factors and
Violation Severity Levels is open through 8 p.m. Eastern on Monday, August 26, 2013.
Background information for this project can be found on the project page.
Instructions

Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
As a reminder, this ballot is being conducted under the revised Standard Processes Manual,
which requires all negative votes to have an associated comment submitted (or an indication of
support of another entity’s comments). Please see NERC’s announcement regarding the balloting
software updates and the guidance document, which explains how to cast your ballot and note if
you’ve made a comment in the online comment form or support another entity’s comment.
Next Steps

The ballot results will be announced and posted on the project page. The drafting team will consider all
comments received during the formal comment period and, if needed, make revisions to the standard.
If the comments do not show the need for significant revisions, the standard will proceed to a final
ballot.

Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2012-05 ATC Revisions (MOD A)

2

Standards Announcement
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Comment Period: July 11, 2013 – August 26, 2013
Ballot Pools Forming Now: July 11, 2013 – August 9, 2013
Upcoming:
Ballot and Non-Binding Poll: August 16-26, 2013
Now Available

A 45-day formal comment period for MOD-001-2 is open through 8 p.m. Eastern on Monday,
August 26, 2013. The standard authorization request (SAR) for this project is also posted for
comment. A ballot pool is being formed and the ballot pool window is open through 8 a.m. Eastern
on Friday, August 9, 2013 (please note that ballot pools close at 8 a.m. Eastern and mark your
calendar accordingly).
This project began with an informal development process to address outstanding FERC directives from
Order 729 and other issues based on operational lessons learned. The informal effort resulted in
retiring market-based requirements from six MOD standards and combining the remaining reliability
related components into one proposed standard, MOD-001-2. The goal is to present the standard to
the NERC Board of Trustees in November 2013.
Background information for this project can be found on the project page.
Instructions for Joining Ballot Pool(s)

Ballots pools are being formed for MOD-001-2 and the associated non-binding poll in this project.
Registered Ballot Body members must join the ballot pools to be eligible to vote in the balloting
and submit an opinion for the non-binding polls of the associated VRFs and VSLs. Registered Ballot
Body members may join the ballot pools at the following page: Join Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by
using their “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited
from using the ballot pool list servers.) The list servers for this project are:
Ballot: [email protected]
Non-Binding poll: [email protected]

Instructions for Commenting

A formal comment period is open through 8 p.m. Eastern on Monday, August 26, 2013. Please use
the electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Wendy Muller. An off-line, unofficial copy of the comment form is posted on
the project page.
Next Steps

A ballot for MOD-001-2 and non-binding poll of the associated Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) will be conducted as previously outlined.
Standards Development Process

The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2012-05 ATC Revisions (MOD A) – July 2013

2

Standards Announcement
Project 2012-05 ATC Revisions
Standard Drafting Team

Nomination Period Open through July 22, 2013
Link to Official Nomination Form
Link to Word Version of Nomination Form
Background

The purpose of this project is: (1) to ensure the reliable calculation of Total Flowgate Capability (TFC)
and Total Transfer Capability (TTC) values when those values are used by a Transmission Service
Provider to calculate Available Flowgate Capability (AFC) or Available Transfer Capability (ATC) or
used by a Reliability Coordinator; (2) to require disclosure of how TFC, TTC, Capacity Benefit Margin
(CBM), and Transmission Reliability Margin (TRM) values are calculated for entities with a reliability
need for the information; and (3) to require the sharing of data with other entities with a reliability
need for the AFC, ATC, TFC, TTC, CBM, or TRM values.
We are seeking three individuals who have experience and expertise in the aforementioned areas. If
possible, we would like to add a member from Canada. We are also seeking a lawyer to participate
on the team.
Experience with developing standards inside or outside (e.g., IEEE, NAESB, ANSI, etc.) of the NERC
process is beneficial, but is not required, and should be highlighted in the information submitted if
applicable.
Instructions for Submitting a Nomination

If you are interested in serving on the Standard Drafting Team, please complete this nomination
form by July 22, 2013. The nomination form should be submitted describing the individual’s
experience or qualifications related to the project.
An unofficial Word version of the nomination form is also posted on the Standard Drafting Team
Vacancies page.

Standards Development Process

The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder participation.
We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd.NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2012-05 ATC Revisions SDT Nomination Period Open | July 2013

2

Standards Announcement
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Ballot and Non-Binding Poll Results
Now Available

A ballot for MOD-001-2 and non-binding poll of the associated Violation Risk Factors (VRFs) and
Violation Severity Levels (VSLs) concluded at 8 p.m. Eastern on Monday, August 26, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results
for the ballot.
Approval

Non-binding Poll Results

Quorum: 76.14%

Quorum: 75.98%

Approval: 51.10%

Supportive Opinions: 53.29%

Background information for this project can be found on the project page.
Next Steps

The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. The standard will then proceed to an additional comment
period and ballot.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

NERC Standards
Newsroom  •  Site Map  •  Contact NERC

Advanced Search

User Name

Ballot Results

Ballot Name: Project 2012-05 ATC Revisions MOD A (MOD-001-2)

Password

Ballot Period: 8/16/2013 - 8/27/2013
Log in

Ballot Type: Initial
Total # Votes: 284

Register

Total Ballot Pool: 373
Quorum: 76.14 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
51.10 %
Vote:
Ballot Results: The standard will proceed to an additional ballot.

 Home Page
Summary of Ballot Results

Affirmative

Negative

Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote

1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals

1
2
3
4
5
6
7
8
9

106

1

32

0.451

39

0.549

1

9

25

10

0.6

2

0.2

4

0.4

0

1

3

82

1

28

0.483

30

0.517

0

6

18

28

1

9

0.529

8

0.471

0

2

9

82

1

24

0.471

27

0.529

0

8

23

52

1

20

0.541

17

0.459

0

5

10

0

0

0

0

0

0

0

0

0

4

0.3

0

0

3

0.3

0

0

1

2

0.2

1

0.1

1

0.1

0

0

0

7

0.7

7

0.7

0

0

0

0

0

373

6.8

123

3.475

129

3.325

1

31

89

Individual Ballot Pool Results

Ballot
Segment

1
1

1

Organization

Member

Ameren Services

American Electric Power

Vijay Sankar
Eric Scott

Paul B Johnson

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

NERC
Notes

Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz

NERC Standards

1

American Transmission Company, LLC

Andrew Z Pusztai

1

Arizona Public Service Co.

Robert Smith

1

Associated Electric Cooperative, Inc.

John Bussman

1

ATCO Electric

Glen Sutton

1
1

Austin Energy
Avista Utilities

James Armke
Heather Rosentrater

1

Balancing Authority of Northern California

Kevin Smith

1

Baltimore Gas & Electric Company

Christopher J Scanlon

1

BC Hydro and Power Authority

Patricia Robertson

Negative

1
1
1
1

Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC

Donald S. Watkins
Tony Kroskey
John C Fontenot
John Brockhan

Affirmative

1

Central Electric Power Cooperative

Michael B Bax

1

Joseph Turano Jr.

Affirmative

Chang G Choi

Affirmative

1

Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee

Daniel S Langston

Affirmative

1

Clark Public Utilities

Jack Stamper

1
1

Cleco Power LLC
Colorado Springs Utilities

1

Consolidated Edison Co. of New York

1
1
1
1
1

CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power

Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley

1

Duke Energy Carolina

Douglas E. Hils

Negative

1
1
1

El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.

Pablo Onate
Oliver A Burke
William J Smith

Abstain

1

Florida Keys Electric Cooperative Assoc.

Dennis Minton

1

Florida Power & Light Co.

Mike O'Neil

1

1

Gainesville Regional Utilities

Richard Bachmeier

1
1

Georgia Transmission Corporation
Great River Energy

Jason Snodgrass
Gordon Pietsch

Negative

Affirmative
Negative

Negative

Negative

COMMENT
RECEIVED

Affirmative
COMMENT
RECEIVED

Abstain
Negative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

COMMENT
RECEIVED

Affirmative
Affirmative

Abstain
SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)

Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency)

Affirmative
Abstain

Hydro One Networks, Inc.

Ajay Garg

1
1

Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp

Martin Boisvert
Molly Devine

Affirmative
Abstain

Michael Moltane

Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS (AECI)
NO COMMENT
RECEIVED

Affirmative
Affirmative

1

1

American
Electric Power)
SUPPORTS
THIRD PARTY
COMMENTS (Midwest
Reliability
Organization)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Hydro One,
NPCC RSC)

NERC Standards

1

JDRJC Associates

Jim D Cyrulewski

1

JEA

Ted Hobson

Negative
Affirmative

1

KAMO Electric Cooperative

Walter Kenyon

Negative

1

Kansas City Power & Light Co.

Jennifer Flandermeyer

Negative

1

Lakeland Electric

Larry E Watt

Negative

1

Lee County Electric Cooperative

John Chin

1

Lincoln Electric System

Doug Bantam

1

Long Island Power Authority

Robert Ganley

Negative

1

Lower Colorado River Authority

Martyn Turner

Negative

1

M & A Electric Power Cooperative

William Price

Negative

1

Manitoba Hydro

Nazra S Gladu

Negative

1

MEAG Power

Danny Dees

Negative

1
1
1

MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water

Terry Harbour
Daniel L Inman
Andrew J Kurriger

1

N.W. Electric Power Cooperative, Inc.

Mark Ramsey

Negative

1

National Grid USA

Michael Jones

Affirmative

1

Nebraska Public Power District

Cole C Brodine

Negative

1

New Brunswick Power Transmission
Corporation

Randy MacDonald

SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency
(FMPA))
SUPPORTS
THIRD PARTY
COMMENTS (In support of
the SPP
Reliability
Standards
Review Group)
SUPPORTS
THIRD PARTY
COMMENTS (Snohomish
County Public
Utility District)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Snohomish
and FMPA)

Affirmative
Affirmative

1

New York Power Authority

Bruce Metruck

Negative

1

Northeast Missouri Electric Power
Cooperative

Kevin White

Negative

1

Northeast Utilities

David Boguslawski

1

Northern Indiana Public Service Co.

Julaine Dyke

1

NorthWestern Energy

John Canavan

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS (MISO)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (MRO-NSRF)

SUPPORTS
THIRD PARTY
COMMENTS (SNOPUD and
NPCC)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED

Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY

NERC Standards
1

Ohio Valley Electric Corp.

Robert Mattey

Negative

1

Oklahoma Gas and Electric Co.

Terri Pyle

Negative

1

Omaha Public Power District

Doug Peterchuck

Negative

1
1
1
1
1
1

Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority

Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
Ryan Millard
John C. Collins

1

Portland General Electric Co.

John T Walker

1
1
1

Brenda L Truhe
Laurie Williams
Kenneth D. Brown

1
1

PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.

1

Sacramento Municipal Utility District

Tim Kelley

1
1
1

Salt River Project
San Diego Gas & Electric
SaskPower

Robert Kondziolka
Will Speer
Wayne Guttormson

1

COMMENTS (Thomas Foltz
- American
Electric Power)
SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)

Affirmative

Abstain
Negative

COMMENT
RECEIVED

Affirmative

Dale Dunckel
Denise M Lietz
John C. Allen

Abstain
Affirmative
Negative
Affirmative

1

Seattle City Light

Pawel Krupa

Negative

1

Sho-Me Power Electric Cooperative

Denise Stevens

Negative

1

Sierra Pacific Power Co.

Rich Salgo

1

Snohomish County PUD No. 1

Long T Duong

1
1

South Carolina Electric & Gas Co.
South Carolina Public Service Authority

Tom Hanzlik
Shawn T Abrams

1

Southern California Edison Company

Steven Mavis

1

Southern Company Services, Inc.

Robert A. Schaffeld

SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))
SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Affirmative
Negative

COMMENT
RECEIVED

Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Affirmative

1

Southwest Transmission Cooperative, Inc.

John Shaver

Negative

1

Sunflower Electric Power Corporation

Noman Lee Williams

Negative

1

Tampa Electric Co.

Beth Young

1

Tennessee Valley Authority

Howell D Scott

1
1
1
1

Texas Municipal Power Agency
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
U.S. Bureau of Reclamation

Brent J Hebert
Steven Powell
Tracy Sliman
Richard T Jackson

1

United Illuminating Co.

Jonathan Appelbaum

1
1
1

Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

Allen Klassen
Lloyd A Linke
Gregory L Pieper

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

COMMENT
RECEIVED

Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES
Comments)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain

COMMENT
RECEIVED

NERC Standards

2

BC Hydro

Venkataramakrishnan
Vinnakota

2
2

California ISO
Electric Reliability Council of Texas, Inc.

Rich Vine
Cheryl Moseley

2

Independent Electricity System Operator

Barbara Constantinescu

Negative

2

ISO New England, Inc.

Kathleen Goodman

Negative

2
2
2
2

Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.

Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon

Affirmative

2

Southwest Power Pool, Inc.

Charles H. Yeung

Negative

3

AEP

Michael E Deloach

Negative

3
3

Alabama Power Company
Ameren Services

Robert S Moore
Mark Peters

Affirmative
Abstain

3

Associated Electric Cooperative, Inc.

Chris W Bolick

Negative

3

Avista Corp.

Scott J Kinney

Affirmative

Negative

Affirmative
Abstain

3

BC Hydro and Power Authority

Pat G. Harrington

Negative

3

Bonneville Power Administration

Rebecca Berdahl

Affirmative

3

Central Electric Power Cooperative

Adam M Weber

3
3
3
3

City
City
City
City

Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson

of
of
of
of

Austin dba Austin Energy
Bartow, Florida
Clewiston
Farmington

3

City of Redding

Bill Hughes

3
3

City of Tallahassee
Cleco Corporation

Bill R Fowler
Michelle A Corley

3

Colorado Springs Utilities

Charles Morgan

3
3
3

ComEd
Consolidated Edison Co. of New York
CPS Energy

John Bee
Peter T Yost
Jose Escamilla

Negative

COMMENT
RECEIVED
COMMENT
RECEIVED

SUPPORTS
THIRD PARTY
COMMENTS (ISO RTO SRC)
SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz)

SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Patricia
Robertson)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)

Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (SMUD)

Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Colorado
Springs
Utilities)

Affirmative
Affirmative

3

Detroit Edison Company

Kent Kujala

Negative

3
3
3

Dominion Resources, Inc.
Entergy
FirstEnergy Corp.

Connie B Lowe
Joel T Plessinger
Cindy E Stewart

Abstain

3

Florida Municipal Power Agency

Joe McKinney

3

Florida Power & Light Co.

Summer C Esquerre

3

Florida Power Corporation

Lee Schuster

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS - (
Patricia
Robertson)

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Munical Power
Agency)

Affirmative
Negative

Negative

COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS -

NERC Standards
(Duke Energy)
3
3
3
3

Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company

Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell

Affirmative
Affirmative

3

Hydro One Networks, Inc.

David Kiguel

3
3

Imperial Irrigation District
JEA

Jesus S. Alcaraz
Garry Baker

3

KAMO Electric Cooperative

Theodore J Hilmes

Negative

3

Kansas City Power & Light Co.

Charles Locke

Negative

3

Kissimmee Utility Authority

Gregory D Woessner

Affirmative
Negative

COMMENT
RECEIVED

Affirmative

3

Lakeland Electric

Mace D Hunter

Negative

3

Lincoln Electric System

Jason Fortik

Negative

3
3

Los Angeles Department of Water & Power
Louisville Gas and Electric Co.

Mike Anctil
Charles A. Freibert

SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA
comments,
which also are
being
supported by
SPP-Robert
Rhodes)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency)
SUPPORTS
THIRD PARTY
COMMENTS (SPP Reliability
Standards
Review Group)

Affirmative
Affirmative

3

M & A Electric Power Cooperative

Stephen D Pogue

Negative

3

Manitoba Hydro

Greg C. Parent

Negative

3

MEAG Power

Roger Brand

Negative

3
3
3

MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District

Thomas C. Mielnik
Jeff Franklin
Jack W Savage

3

Muscatine Power & Water

John S Bos

3

National Grid USA

Brian E Shanahan

SUPPORTS
THIRD PARTY
COMMENTS (Associated
Electric)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Snohomish
and FMPA)

Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)

Affirmative

3

Nebraska Public Power District

Tony Eddleman

Negative

3

New York Power Authority

David R Rivera

Negative

3

Northeast Missouri Electric Power
Cooperative

Skyler Wiegmann

Negative

3

Northern Indiana Public Service Co.

Ramon J Barany

Affirmative

SUPPORTS
THIRD PARTY
COMMENTS (MRO NERC
Standards
Review Forum
(NSRF))
SUPPORTS
THIRD PARTY
COMMENTS (SNOPUD &
NPCC)
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

NERC Standards
3

NW Electric Power Cooperative, Inc.

David McDowell

Negative

3

Oklahoma Gas and Electric Co.

Donald Hargrove

Negative

3
3
3
3
3

Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp

David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner

Affirmative
Affirmative

THIRD PARTY
COMMENTS (AECI)
COMMENT
RECEIVED

Abstain
Negative

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Thomas G Ward

Negative

COMMENT
RECEIVED

Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC

Jeffrey Mueller
Erin Apperson
Eddy Reece
Thomas M Haire

Affirmative

3

Sacramento Municipal Utility District

James Leigh-Kendall

3
3

Salt River Project
Santee Cooper

John T. Underhill
James M Poston

3

Platte River Power Authority

Terry L Baker

3

PNM Resources

Michael Mertz

3

Portland General Electric Co.

3
3
3
3

Abstain
Negative
Affirmative
Affirmative

3

Seattle City Light

Dana Wheelock

Negative

3

Seminole Electric Cooperative, Inc.

James R Frauen

Affirmative

3

Sho-Me Power Electric Cooperative

Jeff L Neas

Negative

3

Snohomish County PUD No. 1

Mark Oens

Negative

3
3
3

South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.

Hubert C Young
Travis Metcalfe
Ronald L. Donahey

3

Tennessee Valley Authority

Ian S Grant

3
3
3
3
3

Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Public Service Corp.
Xcel Energy, Inc.

Mike Swearingen
Janelle Marriott
Bo Jones
Gregory J Le Grave
Michael Ibold

4

Blue Ridge Power Agency

Duane S Dahlquist

4
4

City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission

Reza Ebrahimian
Kevin McCarthy

City of Redding

Nicholas Zettel

4

4

COMMENT
RECEIVED

SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))
SUPPORTS
THIRD PARTY
COMMENTS (AECI)
SUPPORTS
THIRD PARTY
COMMENTS (Kenn
Backholm,
Public Utility
District No.1 of
Snohomish
County)

Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (TVA)

Affirmative
Affirmative
Abstain
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (support the
comments of
Florida
Municipal
Power Agency
(FMPA))

Affirmative

Tim Beyrle

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

Negative

SUPPORTS
THIRD PARTY
COMMENTS (SMUD)

NERC Standards
4
4
4

City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company

John Allen
Margaret Powell

Affirmative

Tracy Goble

Affirmative

4

Detroit Edison Company

Daniel Herring

4

Flathead Electric Cooperative

Russ Schneider

4

Florida Municipal Power Agency

Frank Gaffney

4
4
4
4
4
4
4

Fort Pierce Utilities Authority
Georgia System Operations Corporation
Herb Schrayshuen
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Public Utility District No. 1 of Douglas
County

Cairo Vanegas
Guy Andrews
Herb Schrayshuen
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh

4

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency)

Negative

COMMENT
RECEIVED

Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Henry E. LuBean

4

Public Utility District No. 1 of Snohomish
County

John D Martinsen

Negative

4

Sacramento Municipal Utility District

Mike Ramirez

Negative

4

Seattle City Light

Hao Li

Negative

4
4
4

Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities

Steven R Wallace
Steven McElhaney
Keith Morisette

4

Utility Services, Inc.

Brian Evans-Mongeon

4
4

Wisconsin Energy Corp.
WPPI Energy

Anthony Jankowski
Todd Komplin

5

AEP Service Corp.

Brock Ondayko

5
5
5
5

Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.

Sam Dwyer
Scott Takinen
Matthew Pacobit
Steve Wenke

5

BC Hydro and Power Authority

Clement Ma

5

Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Bonneville Power Administration

5

Brazos Electric Power Cooperative, Inc.

Shari Heino

5

BrightSource Energy, Inc.

Chifong Thomas

5

City and County of San Francisco

Daniel Mason

5

City of Austin dba Austin Energy

Jeanie Doty

5

SUPPORTS
THIRD PARTY
COMMENTS (Kenn
Backholm,
Public Utility
District No.1 of
Snohomish
County)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase
(Seattle City
Light))

Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (NPCC RSC)

Abstain
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Thomas FoltzAmerican
Electric Power)

Abstain
Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS
(Patricia
Robertson - BC
Hydro)

Mike D Kukla
Francis J. Halpin

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Negative

COMMENT
RECEIVED

Affirmative

NERC Standards

5

City of Redding

Paul A. Cummings

5
5
5
5
5
5
5
5
5
5
5

City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.

Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Alexander Eizans
Mike Garton

5

Duke Energy

Dale Q Goodwine

Negative

5
5
5
5
5
5
5

El Paso Electric Company
Electric Power Supply Association
Entergy Services, Inc.
Essential Power, LLC
Exelon Nuclear
First Wind
FirstEnergy Solutions

Gustavo Estrada
John R Cashin
Tracey Stubbs
Patrick Brown
Mark F Draper
John Robertson
Kenneth Dresner

Abstain

5

Florida Municipal Power Agency

David Schumann

Negative

5
5
5

Great River Energy
Hydro-Québec Production
JEA

Preston L Walsh
Roger Dufresne
John J Babik

Abstain

5

Kansas City Power & Light Co.

Brett Holland

Negative

5

Kissimmee Utility Authority

Mike Blough

Negative

5

Lakeland Electric

James M Howard

Negative

5

Lincoln Electric System

Dennis Florom

Negative

5

Los Angeles Department of Water & Power

Kenneth Silver

Affirmative

5

Lower Colorado River Authority

Karin Schweitzer

5

Luminant Generation Company LLC

Rick Terrill

5

Manitoba Hydro

S N Fernando

5

Massachusetts Municipal Wholesale Electric
Company

David Gordon

Negative
Affirmative

Affirmative
Affirmative
Affirmative
Abstain

SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)

Affirmative
Affirmative
COMMENT
RECEIVED

Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal
Power Agency)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (SPP Reliability
Standards
Review Group)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Snohomish
County Public
Utility District)

Negative

COMMENT
RECEIVED

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Snohomish
and FMPA)

5

MEAG Power

Steven Grego

5

MidAmerican Energy Co.

Neil D Hammer

5

Muscatine Power & Water

Mike Avesing

Negative

5

Nebraska Public Power District

Don Schmit

Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS (SMUD)

SUPPORTS
THIRD PARTY
COMMENTS (MRS NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS

NERC Standards

5

New York Power Authority

Wayne Sipperly

Negative

5
5

NextEra Energy
Oglethorpe Power Corporation

Allen D Schriver
Bernard Johnson

Affirmative
Affirmative

5

Oklahoma Gas and Electric Co.

Leo Staples

Negative

5

Omaha Public Power District

Mahmood Z. Safi

Negative

5

Orlando Utilities Commission

Richard K Kinas

5

PacifiCorp

Bonnie Marino-Blair

Negative

5

Portland General Electric Co.

Matt E. Jastram

Negative

5
5
5

Annette M Bannon
Tim Kucey
Steven Grega

5

PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.

Lynda Kupfer

Abstain

5

Sacramento Municipal Utility District

Susan Gill-Zobitz

Negative

5
5

Salt River Project
Santee Cooper

William Alkema
Lewis P Pierce

5

THIRD PARTY
COMMENTS (SNOPD and
NPCC)

SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electrict)
SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (Kelly
Cumiskey,
PacifiCorp)
COMMENT
RECEIVED

Affirmative
Affirmative

Michiko Sell
COMMENT
RECEIVED

Affirmative
Affirmative

5

Seattle City Light

Michael J. Haynes

Negative

5

Seminole Electric Cooperative, Inc.

Brenda K. Atkins

Affirmative

SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase,
Seattle City
Light)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Kenn
Backholm,
Public Utility
District No.1 of
Snohomish
County)

Negative

COMMENT
RECEIVED

5

Snohomish County PUD No. 1

Sam Nietfeld

5

South Carolina Electric & Gas Co.

Edward Magic

5

Southern California Edison Company

Denise Yaffe

5
5
5
5

Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.

William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer

Affirmative
Affirmative
Affirmative
Abstain

5

Tennessee Valley Authority

David Thompson

Negative

COMMENT
RECEIVED

5

Tri-State G & T Association, Inc.

Mark Stein

5

U.S. Army Corps of Engineers

Melissa Kurtz

Negative

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

5
5
5
5
5

USDI Bureau of Reclamation
Westar Energy
Wisconsin Public Service Corp.
WPPI Energy
Xcel Energy, Inc.

Erika Doot
Bryan Taggart
Scott E Johnson
Steven Leovy
Liam Noailles

6

AEP Marketing

Edward P. Cox

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

Abstain
Affirmative
Abstain
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz
American
Electric Power)

NERC Standards
6
6

Ameren Energy Marketing Co.
APS

Jennifer Richardson
Randy A. Young

Affirmative

6

Associated Electric Cooperative, Inc.

Brian Ackermann

Negative

6
6

Bonneville Power Administration
City of Austin dba Austin Energy

Brenda S. Anderson
Lisa L Martin

6

City of Redding

Marvin Briggs

6
6
6
6
6

Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.

Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade

6

Duke Energy

Greg Cecil

6

FirstEnergy Solutions

Kevin Querry

6

Florida Municipal Power Agency

Richard L. Montgomery

6
6
6
6

Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.

Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer

6

Lakeland Electric

Paul Shipps

Negative

6

Lincoln Electric System

Eric Ruskamp

Negative

6
6

Los Angeles Department of Water & Power
Luminant Energy

Brad Packer
Brenda Hampton

6

Manitoba Hydro

Blair Mukanik

6
6

MidAmerican Energy Co.
Modesto Irrigation District

Dennis Kimm
James McFall

Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (SMUD)

Affirmative
Affirmative
Affirmative
Abstain
Negative

SUPPORTS
THIRD PARTY
COMMENTS (Duke Energy)

Affirmative
Negative

COMMENT
RECEIVED

Affirmative

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (SPP Reliability
Standards
Review Group)

Affirmative
Abstain
Negative

6

Muscatine Power & Water

John Stolley

Negative

6

New York Power Authority

Saul Rojas

Negative

6
6

Northern California Power Agency
Northern Indiana Public Service Co.

Steve C Hill
Joseph O'Brien

COMMENT
RECEIVED

SUPPORTS
THIRD PARTY
COMMENTS (MRO NSRF)
SUPPORTS
THIRD PARTY
COMMENTS (SNOPUD and
NPCC)

Affirmative
Affirmative

6

Oklahoma Gas & Electric Services

Jerry Nottnagel

Negative

6

PacifiCorp

Kelly Cumiskey

Negative

6

Platte River Power Authority

Carol Ballantine

Negative

6
6
6
6

Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County

Stephen C Knapp
Elizabeth Davis
Peter Dolan
Hugh A. Owen

6

Sacramento Municipal Utility District

Diane Enderby

Negative

6
6

Salt River Project
Santee Cooper

Steven J Hulet
Michael Brown

Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS (AECI)

SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric Co.)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Affirmative
Affirmative
Affirmative
Abstain
COMMENT
RECEIVED

NERC Standards

6

Seattle City Light

Dennis Sismaet

Negative

6

Seminole Electric Cooperative, Inc.

Trudy S. Novak

Affirmative

6

Snohomish County PUD No. 1

Kenn Backholm

Negative

6

Lujuanna Medina

6
6

Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.

6

Tennessee Valley Authority

Marjorie S. Parsons

6

Westar Energy
Western Area Power Administration - UGP
Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.

Grant L Wilkerson

Affirmative

Peter H Kinney

Affirmative

6

6
6
6
8

Affirmative

David Hathaway
David F Lemmons
Edward C Stein

Abstain
Abstain

Roger C Zaklukiewicz

Negative

8

Massachusetts Attorney General

Frederick R Plett

Negative

8

Volkmann Consulting, Inc.

Terry Volkmann

Negative

10
10
10
10
10
10
10

Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory Utility
Commissioners
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council

Donald Nelson

Copyright © 2012 by the North American Electric Reliability Corporation.  :  All rights reserved.
A New Jersey Nonprofit Corporation

https://standards.nerc.net/BallotResults.aspx?BallotGUID=d8fc8c77-e011-47c2-a1d0-2b06e4606ad5[9/5/2013 1:13:37 PM]

COMMENT
RECEIVED

Negative

Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Steven L. Rueckert

Legal and Privacy
 404.446.2560 voice  :  404.446.2595 fax  
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA  30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801

SUPPORTS
THIRD PARTY
COMMENTS (ISO-NE)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA
comments by
Frank Gaffney)

Affirmative

Diane J. Barney

COMMENT
RECEIVED

Negative

9

COMMENT
RECEIVED

Michael C Hill
Benjamin F Smith II

8

9

John J. Ciza

SUPPORTS
THIRD PARTY
COMMENTS (Paul Haase)

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Non-binding Poll Results
Project 2012-05 MOD A

Non-binding Poll Results

Poll Name: Project 2012-05 ATC Revisions MOD A (MOD-001-2)
Poll Period: 8/16/2013 - 8/29/2013
Total # Opinions: 272
Total Ballot Pool: 358
75.98% of those who registered to participate provided an opinion or an abstention;

Summary Results: 53.29% of those who provided an opinion indicated support for the VRFs and VSLs.
Individual Ballot Pool Results

Segment

Organization

Member

Opinion

1
1
1

Ameren Services
American Electric Power
Arizona Public Service Co.

Eric Scott
Paul B Johnson
Robert Smith

Abstain
Abstain
Affirmative

1

Associated Electric Cooperative, Inc.

John Bussman

Negative

1

ATCO Electric

Glen Sutton

Negative

1
1

1
1
1
1
1

Austin Energy
James Armke
Avista Utilities
Heather Rosentrater
Balancing Authority of Northern
Kevin Smith
California
BC Hydro and Power Authority
Patricia Robertson
Bonneville Power Administration
Donald S. Watkins
Brazos Electric Power Cooperative, Inc. Tony Kroskey
Bryan Texas Utilities
John C Fontenot
CenterPoint Energy Houston Electric, LLC John Brockhan

1

Central Electric Power Cooperative

Michael B Bax

1

Joseph Turano Jr.

Affirmative

Chang G Choi

Affirmative

1
1
1
1

Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma
Power
City of Tallahassee
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities

Affirmative
Negative

1

Consolidated Edison Co. of New York

1
1

CPS Energy
Dairyland Power Coop.

Daniel S Langston
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy

1

1

NERC Notes

SUPPORTS THIRD
PARTY COMMENTS (AECI)
NO COMMENT
RECEIVED

Abstain
Abstain
Negative

COMMENT RECEIVED

Abstain
Affirmative

Abstain
Negative

Affirmative
Affirmative

SUPPORTS THIRD
PARTY COMMENTS (AECI)

COMMENT RECEIVED

1
1
1

Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power

Hertzel Shamash
James Tucker
Michael S Crowley

1

Duke Energy Carolina

Douglas E. Hils

Negative

1
1
1

El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.

Pablo Onate
Oliver A Burke
William J Smith

Abstain

1

Florida Keys Electric Cooperative Assoc. Dennis Minton

1

Florida Power & Light Co.

Mike O'Neil

1

Gainesville Regional Utilities

Richard Bachmeier

1
1

Georgia Transmission Corporation
Great River Energy

Jason Snodgrass
Gordon Pietsch

Abstain

Affirmative
Negative

Negative

Ajay Garg

1
1

Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp

Martin Boisvert
Molly Devine

Affirmative
Abstain

Michael Moltane

Abstain

1

JDRJC Associates

Jim D Cyrulewski

Negative

1

JEA

Ted Hobson

1

KAMO Electric Cooperative

Walter Kenyon

Negative

1

Kansas City Power & Light Co.

Jennifer Flandermeyer

Negative

1

Lakeland Electric

Larry E Watt

Negative

1
1
1

John Chin
Doug Bantam
Robert Ganley

1

Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Los Angeles Department of Water &
Power
Lower Colorado River Authority

1

M & A Electric Power Cooperative

William Price

Negative

1

Manitoba Hydro

Nazra S Gladu

Negative

1

MEAG Power

Danny Dees

Negative

Non-binding Poll Project 2012-05 MOD A

SUPPORTS THIRD
PARTY COMMENTS (Florida Municipal
Power Agency)

Affirmative
Abstain

Hydro One Networks, Inc.

1

SUPPORTS THIRD
PARTY COMMENTS (FMPA)

Affirmative

1

1

SUPPORTS THIRD
PARTY COMMENTS (Duke Energy)

Negative

SUPPORTS THIRD
PARTY COMMENTS (Hydro One, NPCC
RSC)

SUPPORTS THIRD
PARTY COMMENTS (MISO)

Affirmative
SUPPORTS THIRD
PARTY COMMENTS (AECI)
COMMENT RECEIVED
SUPPORTS THIRD
PARTY COMMENTS (Florida Municipal
Power Agency (FMPA))

Abstain
Abstain

John Burnett
Martyn Turner
SUPPORTS THIRD
PARTY COMMENTS (AECI)
COMMENT RECEIVED
SUPPORTS THIRD
PARTY COMMENTS (Snohomish and FMPA)

2

1
1
1

MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water

Terry Harbour
Daniel L Inman
Andrew J Kurriger

1

N.W. Electric Power Cooperative, Inc.

Mark Ramsey

1
1

National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation

Michael Jones
Cole C Brodine

1

New York Power Authority

Bruce Metruck

Negative

1

Northeast Missouri Electric Power
Cooperative

Kevin White

Negative

1

Northeast Utilities

David Boguslawski

Negative

1

Northern Indiana Public Service Co.

Julaine Dyke

1

NorthWestern Energy

John Canavan

Negative

1
1

Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.

Robert Mattey
Terri Pyle

Abstain
Affirmative

1

Omaha Public Power District

Doug Peterchuck

1
1
1
1
1
1
1
1
1
1

Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
Ryan Millard
John C. Collins
John T Walker
Brenda L Truhe
Laurie Williams
Kenneth D. Brown

1
1
1
1
1
1

Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Seattle City Light

1

Sho-Me Power Electric Cooperative

Denise Stevens

1
1

Snohomish County PUD No. 1
South Carolina Electric & Gas Co.

Long T Duong
Tom Hanzlik

1

1

Non-binding Poll Project 2012-05 MOD A

Affirmative
Affirmative

Negative

SUPPORTS THIRD
PARTY COMMENTS (AECI)

Affirmative
Abstain

Randy MacDonald
SUPPORTS THIRD
PARTY COMMENTS (SNOPUD and NPCC)
SUPPORTS THIRD
PARTY COMMENTS (AECI)
SUPPORTS THIRD
PARTY COMMENTS (Northeast Utilities)

Affirmative

Negative

SUPPORTS THIRD
PARTY COMMENTS (FMPA)

SUPPORTS THIRD
PARTY COMMENTS (MRO NSRF)

Affirmative

Abstain
Negative
Affirmative

COMMENT RECEIVED

Dale Dunckel
Denise M Lietz
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa

Abstain
Negative
Affirmative

COMMENT RECEIVED

Abstain
Negative
Negative
Affirmative

SUPPORTS THIRD
PARTY COMMENTS (AECI)
COMMENT RECEIVED

3

1

South Carolina Public Service Authority

Shawn T Abrams

1

Southern California Edison Company

Steven Mavis

1

Southern Company Services, Inc.

Robert A. Schaffeld

1

Southwest Transmission Cooperative,
Inc.

John Shaver

Negative

1

Sunflower Electric Power Corporation

Noman Lee Williams

Negative

1
1
1
1
1
1
1
1
1

Tampa Electric Co.
Tennessee Valley Authority
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

2
2
2
2
2
2
2
2
2
3
3
3

Beth Young
Howell D Scott
Steven Powell
Tracy Sliman
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Venkataramakrishnan
BC Hydro
Vinnakota
California ISO
Rich Vine
Electric Reliability Council of Texas, Inc. Cheryl Moseley
Independent Electricity System Operator Barbara Constantinescu
ISO New England, Inc.
Kathleen Goodman
Midwest ISO, Inc.
Marie Knox
New Brunswick System Operator
Alden Briggs
New York Independent System Operator Gregory Campoli
PJM Interconnection, L.L.C.
stephanie monzon
Southwest Power Pool, Inc.
Charles H. Yeung
AEP
Michael E Deloach
Alabama Power Company
Robert S Moore
Ameren Services
Mark Peters

3

Associated Electric Cooperative, Inc.

Chris W Bolick

3
3
3

Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration

Scott J Kinney
Pat G. Harrington
Rebecca Berdahl

3

Central Electric Power Cooperative

Adam M Weber

3
3
3
3

City
City
City
City

Andrew Gallo
Matt Culverhouse
Lynne Mila
Linda R Jacobson

3

City of Redding

2

of
of
of
of

Austin dba Austin Energy
Bartow, Florida
Clewiston
Farmington

Non-binding Poll Project 2012-05 MOD A

Bill Hughes

Affirmative
Negative

SUPPORTS THIRD
PARTY COMMENTS (FMPA)

Affirmative
SUPPORTS THIRD
PARTY COMMENTS (ACES)
SUPPORTS THIRD
PARTY COMMENTS (ACES)

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Negative

COMMENT RECEIVED

Negative

COMMENT RECEIVED

Affirmative
Abstain
Abstain
Affirmative
Abstain
Negative

SUPPORTS THIRD
PARTY COMMENTS (AECI)

Abstain
Abstain
Affirmative
Negative

SUPPORTS THIRD
PARTY COMMENTS (AECI)

Abstain

Negative

SUPPORTS THIRD
PARTY COMMENTS (SMUD)

4

3
3
3
3
3

City of Tallahassee
Cleco Corporation
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy

Bill R Fowler
Michelle A Corley
Charles Morgan
Peter T Yost
Jose Escamilla

Affirmative
Affirmative
Affirmative

3

Detroit Edison Company

Kent Kujala

Negative

3
3
3
3
3

Dominion Resources, Inc.
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power & Light Co.

Connie B Lowe
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Summer C Esquerre

3

Florida Power Corporation

Lee Schuster

3
3
3
3
3
3
3

Georgia Power Company
Danny Lindsey
Georgia System Operations Corporation Scott McGough
Great River Energy
Brian Glover
Gulf Power Company
Paul C Caldwell
Hydro One Networks, Inc.
David Kiguel
Imperial Irrigation District
Jesus S. Alcaraz
JEA
Garry Baker

3

KAMO Electric Cooperative

Theodore J Hilmes

Negative

3

Kansas City Power & Light Co.

Charles Locke

Negative

3

Kissimmee Utility Authority

Gregory D Woessner

Abstain
Affirmative
Negative

Negative
Affirmative
Affirmative
Abstain
Affirmative
Negative

Lakeland Electric

Mace D Hunter

3

Jason Fortik

3

Lincoln Electric System
Los Angeles Department of Water &
Power
Louisville Gas and Electric Co.

3

M & A Electric Power Cooperative

Stephen D Pogue

Negative

3

Manitoba Hydro

Greg C. Parent

Negative

3

MEAG Power

Roger Brand

Negative

3
3

MidAmerican Energy Co.
Mississippi Power

Thomas C. Mielnik
Jeff Franklin

Non-binding Poll Project 2012-05 MOD A

Mike Anctil

COMMENT RECEIVED
SUPPORTS THIRD
PARTY COMMENTS (Duke Energy)

COMMENT RECEIVED

Affirmative

3

3

SUPPORTS THIRD
PARTY COMMENTS (Florida Municipal
Power Agency)

Negative

SUPPORTS THIRD
PARTY COMMENTS (AECI)
SUPPORTS THIRD
PARTY COMMENTS (FMPA comments,
which also are being
supported by SPPRobert Rhodes)
SUPPORTS THIRD
PARTY COMMENTS (Florida Municipal
Power Agency)

Abstain
Affirmative

Charles A. Freibert
SUPPORTS THIRD
PARTY COMMENTS (Associated Electric)
COMMENT RECEIVED
SUPPORTS THIRD
PARTY COMMENTS (Snohomish and FMPA)

Affirmative
Affirmative

5

3

Modesto Irrigation District

Jack W Savage

3

Muscatine Power & Water

John S Bos

3
3

National Grid USA
Nebraska Public Power District

Brian E Shanahan
Tony Eddleman

3

New York Power Authority

David R Rivera

Negative

3

Northeast Missouri Electric Power
Cooperative

Skyler Wiegmann

Negative

3

Northern Indiana Public Service Co.

Ramon J Barany

Affirmative

3

NW Electric Power Cooperative, Inc.

David McDowell

Negative

3
3
3
3
3
3
3
3

Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources

Donald Hargrove
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz

3

Portland General Electric Co.

Thomas G Ward

3
3
3
3
3
3
3
3
3

Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.

Jeffrey Mueller
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen

3

Sho-Me Power Electric Cooperative

Jeff L Neas

Negative

3

Snohomish County PUD No. 1

Mark Oens

Negative

3
3
3
3
3
3

South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.

Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott

Non-binding Poll Project 2012-05 MOD A

Negative

SUPPORTS THIRD
PARTY COMMENTS (MRO NSRF)

Affirmative
Abstain
SUPPORTS THIRD
PARTY COMMENTS (SNOPUD & NPCC)
SUPPORTS THIRD
PARTY COMMENTS (AECI)
SUPPORTS THIRD
PARTY COMMENTS (AECI)

Affirmative
Affirmative
Abstain

Abstain
Abstain

Negative

SUPPORTS THIRD
PARTY COMMENTS (Comments to be filed
by PGE)

Abstain

Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative

COMMENT RECEIVED

SUPPORTS THIRD
PARTY COMMENTS (AECI)
SUPPORTS THIRD
PARTY COMMENTS (Kenn Backholm, Public
Utility District No.1 of
Snohomish County)

Affirmative
Affirmative
Abstain
Affirmative

6

3
3

Westar Energy
Xcel Energy, Inc.

Bo Jones
Michael Ibold

4

Blue Ridge Power Agency

Duane S Dahlquist

4
4

City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission

Reza Ebrahimian
Kevin McCarthy

4

Affirmative
Abstain

Negative

Abstain

Tim Beyrle

4

City of Redding

Nicholas Zettel

Negative

4

City Utilities of Springfield, Missouri

John Allen

Negative

4

Consumers Energy Company

Tracy Goble

4

Detroit Edison Company

Daniel Herring

4
4
4
4
4
4
4
4

Flathead Electric Cooperative
Florida Municipal Power Agency
Georgia System Operations Corporation
Herb Schrayshuen
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Public Utility District No. 1 of Douglas
County

Russ Schneider
Frank Gaffney
Guy Andrews
Herb Schrayshuen
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh

4

4

4
4
4
4
4
4
4
4
5
5
5
5
5

Non-binding Poll Project 2012-05 MOD A

SUPPORTS THIRD
PARTY COMMENTS (SMUD)
SUPPORTS THIRD
PARTY COMMENTS (SPP RTO)

Affirmative
Negative

Negative
Affirmative
Affirmative
Abstain
Abstain

SUPPORTS THIRD
PARTY COMMENTS (Florida Municipal
Power Agency)
COMMENT RECEIVED

Affirmative

Henry E. LuBean

Public Utility District No. 1 of Snohomish
John D Martinsen
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power
Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.

SUPPORTS THIRD
PARTY COMMENTS - (I
support the comments
of Florida Muncipal
Power Agency (FMPA))

Mike Ramirez
Hao Li
Steven R Wallace

Negative

Negative
Abstain

SUPPORTS THIRD
PARTY COMMENTS (Kenn Backholm, Public
Utility District No.1 of
Snohomish County)
COMMENT RECEIVED

Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Todd Komplin
Brock Ondayko
Sam Dwyer
Scott Takinen
Matthew Pacobit
Steve Wenke

Affirmative
Abstain
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain

7

5

5

BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky
Mike D Kukla
peak power plant project
Bonneville Power Administration
Francis J. Halpin

5

Brazos Electric Power Cooperative, Inc.

Shari Heino

5
5
5

BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy

Chifong Thomas
Daniel Mason
Jeanie Doty

5

City of Redding

Paul A. Cummings

Negative

5
5
5

Karen Webb
Steve Rose
Stephanie Huffman

Affirmative

5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management,
LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
El Paso Electric Company
Electric Power Supply Association
Entergy Services, Inc.
Essential Power, LLC
First Wind
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
Hydro-Québec Production
JEA
Kansas City Power & Light Co.

Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Alexander Eizans
Mike Garton
Dale Q Goodwine
Gustavo Estrada
John R Cashin
Tracey Stubbs
Patrick Brown
John Robertson
Kenneth Dresner
David Schumann
Preston L Walsh
Roger Dufresne
John J Babik
Brett Holland

5

Kissimmee Utility Authority

Mike Blough

5
5

Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water &
Power

James M Howard
Dennis Florom

Abstain
Abstain

Kenneth Silver

Abstain

5

5

5

Abstain

Affirmative
Negative

Affirmative
SUPPORTS THIRD
PARTY COMMENTS (SMUD)

Mike D Hirst
Affirmative
Affirmative
Affirmative
Abstain

Negative
Abstain

COMMENT RECEIVED

Abstain

Affirmative
Negative
Abstain
Abstain
Affirmative
Negative
Negative

5

Lower Colorado River Authority

Karin Schweitzer

Negative

5

Luminant Generation Company LLC

Rick Terrill

Negative

Non-binding Poll Project 2012-05 MOD A

SUPPORTS THIRD
PARTY COMMENTS (ACES)

COMMENT RECEIVED

COMMENT RECEIVED
SUPPORTS THIRD
PARTY COMMENTS (Florida Municipal
Power Agency)

SUPPORTS THIRD
PARTY COMMENTS (Snohomish County
Public Utility District)
COMMENT RECEIVED

8

5
5

Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company

S N Fernando

Negative

COMMENT RECEIVED

Negative

SUPPORTS THIRD
PARTY COMMENTS (Snohomish and FMPA)

Negative

SUPPORTS THIRD
PARTY COMMENTS (MRO NSRF)

David Gordon

5

MEAG Power

Steven Grego

5

MidAmerican Energy Co.

Neil D Hammer

5

Muscatine Power & Water

Mike Avesing

5

Nebraska Public Power District

Don Schmit

5

New York Power Authority

Wayne Sipperly

Negative

5
5
5

NextEra Energy
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.

Allen D Schriver
Bernard Johnson
Leo Staples

Affirmative
Affirmative
Affirmative

5

Omaha Public Power District

Mahmood Z. Safi

Negative

5
5
5
5
5

Orlando Utilities Commission
PacifiCorp
Portland General Electric Co.
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis
County
Public Utility District No. 2 of Grant
County, Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.

Richard K Kinas
Bonnie Marino-Blair
Matt E. Jastram
Annette M Bannon
Tim Kucey

5
5
5
5
5
5
5
5

Abstain
Negative
Affirmative
Abstain

SUPPORTS THIRD
PARTY COMMENTS (SNOPD and NPCC)

SUPPORTS THIRD
PARTY COMMENTS (MRO NSRF)

COMMENT RECEIVED

Steven Grega
Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins

5

Snohomish County PUD No. 1

Sam Nietfeld

5
5
5
5
5
5
5
5

South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.

Edward Magic
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Mark Stein

5

U.S. Army Corps of Engineers

Melissa Kurtz

Non-binding Poll Project 2012-05 MOD A

Abstain

Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative

Negative

Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain

Negative

COMMENT RECEIVED

SUPPORTS THIRD
PARTY COMMENTS (Kenn Backholm, Public
Utility District No.1 of
Snohomish County)
COMMENT RECEIVED

SUPPORTS THIRD
PARTY COMMENTS (FMPA)

9

5
5
5
5
6
6
6

USDI Bureau of Reclamation
Wisconsin Public Service Corp.
WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS

Erika Doot
Scott E Johnson
Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young

6

Associated Electric Cooperative, Inc.

Brian Ackermann

6
6

Bonneville Power Administration
City of Austin dba Austin Energy

Brenda S. Anderson
Lisa L Martin

6

City of Redding

Marvin Briggs

6
6
6

Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York

Robert Hirchak
Shannon Fair
David Balban

6

Duke Energy

Greg Cecil

6
6
6
6
6
6

FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.

Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Donna Stephenson
Jessica L Klinghoffer

6

Lakeland Electric

Paul Shipps

6

Eric Ruskamp

6
6
6
6

Lincoln Electric System
Los Angeles Department of Water &
Power
Luminant Energy
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District

Brenda Hampton
Blair Mukanik
Dennis Kimm
James McFall

Abstain
Negative

6

Muscatine Power & Water

John Stolley

Negative

6

New York Power Authority

Saul Rojas

Negative

6
6
6
6

Northern California Power Agency
Northern Indiana Public Service Co.
Oklahoma Gas & Electric Services
PacifiCorp

Steve C Hill
Joseph O'Brien
Jerry Nottnagel
Kelly Cumiskey

Affirmative
Affirmative
Affirmative
Abstain

6

Platte River Power Authority

Carol Ballantine

Negative

6

Non-binding Poll Project 2012-05 MOD A

Brad Packer

Abstain
Abstain
Affirmative
Abstain
Affirmative
Negative

SUPPORTS THIRD
PARTY COMMENTS (AECI)

Affirmative
Abstain
Negative

SUPPORTS THIRD
PARTY COMMENTS (SMUD)

Affirmative
Affirmative
Negative
Affirmative
Negative

SUPPORTS THIRD
PARTY COMMENTS (Duke Energy)
COMMENT RECEIVED

Affirmative

Negative

SUPPORTS THIRD
PARTY COMMENTS (FMPA)

Abstain
Affirmative
COMMENT RECEIVED

SUPPORTS THIRD
PARTY COMMENTS (MRO NSR)
SUPPORTS THIRD
PARTY COMMENTS (SNOPUD and NPCC)

SUPPORTS THIRD
PARTY COMMENTS (FMPA)

10

6
6
6

Hugh A. Owen

Abstain

6
6
6

Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan
County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper

Diane Enderby
Steven J Hulet
Michael Brown

Negative
Affirmative
Affirmative

6

Seattle City Light

Dennis Sismaet

Negative

6
6
6

Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration UGP Marketing
Xcel Energy, Inc.

Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Affirmative
Negative

John J. Ciza

Affirmative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Abstain
Affirmative

Peter H Kinney

Affirmative

6

6
6
6
6
6
6
6
8
8

Stephen C Knapp
Elizabeth Davis
Peter Dolan

David F Lemmons
Edward C Stein

Affirmative
Affirmative
Abstain

Roger C Zaklukiewicz

Negative

Massachusetts Attorney General

Frederick R Plett

Negative

8

Volkmann Consulting, Inc.

Terry Volkmann

Negative

10
10
10
10
10
10
10

Commonwealth of Massachusetts
Department of Public Utilities
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council

Non-binding Poll Project 2012-05 MOD A

SUPPORTS THIRD
PARTY COMMENTS (Paul Haase)
COMMENT RECEIVED

Abstain

8

9

COMMENT RECEIVED

Donald Nelson

Affirmative

Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Steven L. Rueckert

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

SUPPORTS THIRD
PARTY COMMENTS (ISO-NE)
SUPPORTS THIRD
PARTY COMMENTS (FMPA)
SUPPORTS THIRD
PARTY COMMENTS (FMPA comments by
Frank Gaffney)

11

Individual or group. (51 Responses)
Name (31 Responses)
Organization (31 Responses)
Group Name (20 Responses)
Lead Contact (20 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT
ENTERING ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (9 Responses)
Comments (51 Responses)
Question 1 (37 Responses)
Question 1 Comments (42 Responses)
Question 2 (34 Responses)
Question 2 Comments (42 Responses)
Question 3 (0 Responses)
Question 3 Comments (42 Responses)

Group
MRO NERC Standards Review Forum
Russel Mountjoy
No
No
The NSRF appericiates the effort of the ad hoc team in consolidating 6 standards in to one single
MOD-001-2, particularly, the intention to keep the focus on developing and retaining requirements
with material impact to the reliability of BES. The NSRF has the following recommendation in order to
provide clarity to the proposed Standard. For Applicability 4.1.1, remove the reference to the
Transmission Operator. For R1 and M1, change the responsibility from the Transmission Operator
(TOP) to the Transmission Service Provider (TSP). We agree with the rationale offered by the Florida
Municipal Power Agency (FMPA) regarding this change. In addition, we recognize that Project 2012-05
would also need to include conforming changes to the NERC Functional Reliability Model
responsibilities of the TOP and TSP. For R4 and M4, change the responsibility from the Transmission
Operator (TOP) to the Transmission Service Provider (TSP). We agree with the rationale offered by
the Florida Municipal Power Agency (FMPA) regarding this change. In addition, we recognize that the
Project 2012-05 would also need to include conforming changes to the TRMID definition in the NERC
Glossary of Terms. For R5 and M5, change the responsibilities to refer only to the Transmission
Service Provider (TSP).
Individual
Ross Kovacs
Georgia Transmission Corporation
No
No
No changes to the Requirements, excellent work by the MOD A team. The draft VSLs may need more
work for Requirements 2 through 5; only Severe VSLs are included in the pro forma standard.
Individual
Joe O'Brien
NIPSCO
No

We support this project and the SAR.
No
As a TOP, TP, RP, and LSE in MISO, we do very little to comply with the present AFC MOD Standards
(MOD-001, 004, 008, 030). MISO, a TSP, performs all the related work and the region reviews the
applicable evidence at MISO. As a result a CFR has been drafted to formalize this arrangement and
may be approved by FERC soon. (note that MISO uses FG methodology, n/a for MOD-028 and MOD029). Regarding the MOD-A project, we would like to see the new standard written to reflect who is
actually doing the work. To that end please consider the following revisions to the latest draft: In R1
and R4, replace “Transmission Operator” with “Transmission Operator or Transmission Service
Provider” and in R5 replace “each Transmission Service Provider and Transmission Operator” with
“each Transmission Service Provider or Transmission Operator”. Similar wording is used in R6. Thanks
Individual
Thomas Foltz
American Electric Power
Yes
The Transmission Operator should not be obligated to perform duties that they don't actually perform
in practice. In AEP’s case for example, these obligations fall to the Transmission Service Provider.
These proposed requirements do not accurately represent the way this work is performed in SPP or
PJM. As a result, either a) the Transmission Operator should be replaced by Reliability Coordinator or
Planning Authority as the Functional Entity in Section 4.1. or b) the standard should be re-written to
be flexible enough to accommodate situations where the RTO peforms this role.
Though we support the overall efforts of the drafting team and the integration and consolidation of
the proposed standards, AEP is choosing to vote negative on this project due to our objection to the
Transmission Operator as an applicable Functional Entity, and does accommodate when the RTO
performs this role. Due to the current volume of standards development activity, AEP is not able to
apply the same level of rigor to this request for comment as we would normally. As a result, the
comments provided in this response are those we deemed the most significant, and do not necessary
reflect all the issues that AEP may, at some time, choose to address.
Individual
Catherine Wesley
PJM Interconnection
No
No
While we support the changes to the proposed standard we still think that in general these
requirements could be better suited as NAESB business practices in the long term.
•Recommendation to include in R2 (ATCID) similar language that is in R1 for ATC calculations. •PJM
supports language in R6 specific to the data sharing for AFC, ATC, TFC or TTC calculations as being
required to support data sharing and transparency.
Group
Northeast Power Coordinating Council
Guy Zito
Yes
We agree with the general direction and the scope of revisions proposed in the SAR. However, there
is a basic process and due diligence issue that deserves more focus than is being proposed. The basic
issue is not so much about combining some displaced requirements; the issue is “What should be
retained in the NERC Reliability Standards and what should be mapped to and adopted by NAESB as
business practices, and what is NAESB’s input to the proposed mapping and what is its work plan to

implement such mapping.” It must be emphasized that there is apparently a lack of coordination with
other standard setting organizations to ensure the proposed retirements are properly managed and
that parallel standard development activities will take place to implement standard changes at the
same time. In general, we believe that regulatory authorities and industry participants support the
concept that NERC address reliability and that NAESB address business practices. The Industry needs
to weigh in on the discussion that leads to a recommendation as to which part goes where. However,
as proposed, this posting is as a reliability standard only – there are no questions regarding the
business practices or the NAESB issue. The SAR states that part of the objective is to retire marketbased requirements, which we support; but the SAR is silent on any details which provide specificity
on the scope of the proposed retirements, or transfer of the retired requirements to other standard
setting organizations. The mapping document does not provide specific recommendations on which
retired requirements are to be transferred to NAESB or other standard setting organizations. It is
conceivable that some of the retired requirements will not have a home elsewhere but industry
participants will need to adhere to such requirements, which may be processes or procedures, to
support their business activities. Based on our understanding, NAESB has not been engaged in
providing inputs on the proposed retirement, nor does it have any work plan to implement any or all
of the proposed retired requirements. The draft Implementation Plan being posted mentions a
proposed coordination process, but until NAESB has provided its inputs, the proposed process has not
yet received the support from the party who is partly responsible for the successful and timely
transfer of the NERC retired requirements. In previous projects, a close coordination between NERC
and NAESB was achieved to ensure both parties agreed on the proposed mapping of NERC standard
requirements, and that both were able and ready to implement the proposed changes to ensure a
smooth transition without unduly impacting industry participants. For this project, from the available
documents and based on our knowledge of the current activities, we are not convinced that the
needed coordination with and inputs from NAESB have taken place.
No
(1) We do not agree with the Purpose statement as presented as it contains an unclear objective. The
Purpose statement starts off with “To ensure the reliable calculation of Total Flowgate Capability (TFC)
and Total Transfer Capability (TTC) values…”. We do not think it appropriate to have an objective of
“reliable calculation” in a NERC Reliability Standard; rather, we would see a need for a Reliability
Standard having an objective to calculate TTC and ATC whose values provide a reliability basis for
transmission service reservation and utilization. We therefore suggest the Purpose statement be
revised as follows: Purpose: (1) To ensure the calculated values of Total Flowgate Capability (TFC)
and Total Transfer Capability (TTC) provide a reliability basis when those values are used by a
Transmission Service Provider to calculate Available Flowgate Capability (AFC) or Available Transfer
Capability (ATC) or used by a Reliability Coordinator; (2)…. Further, Items (2) and (3) in the Purpose
statement are not objectives or desired outcomes, they are actions or requirements. We suggest that
(2) and (3) be reworded and combined as follows: To ensure sharing of information on the
methodology and calculated values of TFC, TTC, AFC, ATC, Capacity Benefit Margin (CBM), and
Transmission Reliability Margin (TRM) with entities having a reliability need for the information. (2)
Part 1.1: It is unclear to us what the “this” in “A description of how this is accomplished;” means. Is it
the statement required in Part 1.1, or is it the methodology or the incorporation of facility ratings,
voltage limits, and stability limits pre and post-contingency. This is unclear and can lead to a
Responsible Entity being unable to meet the Standard’s requirements. (3) R3: The second part is not
required. If a TSP does not use CBM, then there is no need for the TSP to have a CBMID on which the
TSP states that it doesn’t use CBM. This exclusion can be stated in the Applicability Section, or in the
Measures. (4) R4: Same comment as in (3) preceding, except this is for TRM. (5) R5: The main
requirement stipulates that: “Within 30 calendar days of receiving a written request that references
this requirement…”, it is unclear whether “this requirement” means R5, and if so, it would be clearer
to just say Requirement R5. Also, do the requesting entities need to reference R5 to substantiate a
request? If so, what is the rationale behind having to make this reference when the latter part of the
requirement addresses the alternative scenarios in which such a reference is not required? NPCC
participating members believe that requirements R5 and 6 should be eliminated under the P81
criteria; and therefore suggest deleting. However, if the Standard Drafting Team believes these
Requirements are necessary for reliability we request an explanation and offer the following
corrections: (6) R5, Parts 5.2 and 5.3: According to R3 and R4, the TSP is required to develop a

CBMID whereas the TOP is required to develop a TRMID. However, Part 5.1 requires that the TOP
provide the CBMID while the TSP is required to provide the TRMID upon requests. The responsibilities
of the TOP and the TSP seem to be incorrect in meeting the requests. (7) M5: Requirement R5 holds
the TOP and TSP responsible for responding to requests for information. However, Measure M5 only
lists the examples of evidence that the TSP needs to provide, but not the TOP. There is thus no
Measure for the TOP to aid its provision of evidence to demonstrate compliance. We suspect this is an
oversight. (8) R6: the same comment with respect to making a reference to “this requirement” as
noted in (7) preceding. (9) R6, Part 6.1: This part appears to be a requirement for the requesters, but
the part is not written to clearly indicate that. To avoid being interpreted as a requirement for the
requester, we suggest to revise the main requirement R6 as follows: R6. Within 30 days of a written
request that references this requirement from another Transmission Service Provider or Transmission
Operator that specifies that the data is for use in the requesting party’s AFC, ATC, TFC, or TTC
calculations, a Transmission Service Provider or Transmission Operator shall share data used in their
respective AFC, ATC, TFC, or TTC calculations (subject to confidentiality, regulatory, or security
requirements). The proposed change will turn an apparent requirement for the requesters into a
condition for a valid request. (10) R6, Part 6.2: This is not a requirement, but a provision for the TSP
and TOP to not have to do anything extra. We do not see the need for having this part to anticipate
that there will be requests for data in a format that is different than the one a TSP or TOP uses,
maintains, or currently makes available to others. If the SDT really wants to relieve the burden of the
TSP and TOP from having to change the data format when such requests are made, the SDT may
want to insert words such as “in the format that is currently used, maintained or made available”
prior to “in their respective…” in the main requirement.
Individual
Denise Yaffe
Southern California Edison
No
No
SCE believes that the calculation of Total Transfer Capabilities and Total Flowgate Capabilities should
be assigned to Transmission Service Providers, rather than to Transmission Operators.
Individual
Daniel Mason
HHWP
Yes
TOP's without ATC Paths and without transmission capacity that is sold through a TSP should be
exempt from the applicabilty of MOD-001. An explicit exclusion is needed to ensure that resources are
not being devoted to actions that produce no reliability benefit.

Group
PacifiCorp
Kelly Cumiskey
No
None relating to the scope of the standard.
No
None that haven’t been retained.
1) PacifiCorp is concerned that the language under M4 exceeds what an entity is required to provide
to sufficiently meet compliance with R4. The current draft of the pro-forma standard states the
following under R4: “Each TOP shall prepare, keep current, and implement a TRMID that describes its

method for establishing margins to protect system reliability.” PacifiCorp maintains that a dated
effective TRMID that is posted on the Transmission Operators website would be an appropriate
example of evidence for meeting compliance with this requirement, however, the current language
under M4 would require an entity to provide a dated effective TRMID and a “demonstration,” such as
a study report, that select currently active values of TRM were determined per the TRMID. The
addition of a study report as a required piece of evidence is absent in the current version of MOD-008.
As such, it’s inclusion in the new standard transcends the intent of the requirement and the goal of
the consolidation of the MOD A standards. PacifiCorp recommends removing the inclusion from M4
language; 2) PacifiCorp would like clarification on whether or not the periodicity highlighted in R1.4
implies that any updates to TFC or TTC should be regularly scheduled, or, should be provided on an
as needed basis? PacifiCorp maintains that in the absence of significant changes to a path, requiring a
specific cycle of updates is arbitrary to both functional entities.
Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County
No
No
Snohomish supports the Project 2012-05 ATC Revisions (MOD A) Standard Drafting Team in its efforts
to combine and clarify the family of MOD Reliability Standards that address transmission and its
associated margins, methodologies, and related factors. However Snohomish is concerned with the
“if” language in R1 and will be voting negative. Snohomish cannot identify any reliability benefits in
applying MOD-001-2 to a TOP that does not operate facilities that a Transmission Service Provider
uses to provide transmission service. In addition Snohomish does not perceive any reliability benefits
to a TOP that does not operate facilities that are not part of a Flowgate or transfer path: does not
contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating
Limit (IROL). Below is the Applicability language for the Project 2012-05 ATC Revisions (MOD A) MOD-001-2. Snohomish is proposing Exemptions 4.2.2 and 4.2.3. Applicability: 4.1. Functional Entity
4.1.1 Transmission Operator 4.1.2 Transmission Service Provider 4.2. Exemptions: The following is
exempt from MOD-001-2. 4.2.1 Functional Entities operating within ERCOT 4.2.2 A Transmission
Operator that does not operate facilities that a Transmission Service Provider uses to provide
transmission service. 4.2.3 A Transmission Operator that operates facilities that are not part of a
Flowgate or transfer path: does not contain a monitored Facility of a permanent Flowgate in the
Eastern Interconnection, a major transfer path within the Western Interconnection, or a comparable
monitored Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included
in an Interconnection Reliability Operating Limit (IROL). Snohomish intents to change its ballots from
negative to affirmative if the proposed language above or other comparable changes are made to
ensure that the MOD-001-2 Reliability Standard is not applicable to TOPs that are not used by TSP to
provide transmission service and are not operating facilities that are monitored elements on Flowgate
or major transformer paths as noted above. Thank you for the opportunity to provide comments.
Individual
Ross Kovacs
Georgia Transmission Corporation
No
No
No comments.
Individual

Jack Stamper
Clark Public Utilities
No
No
Clark supports the Project 2012-05 ATC Revisions (MOD A) Standard Drafting Team in its efforts to
combine and clarify the family of MOD Reliability Standards that address transmission and its
associated margins, methodologies, and related factors. However Clark is concerned with the “if”
language in R1 and will be voting negative. Clark cannot identify any reliability benefits in applying
MOD-001-2 to a TOP that does not operate facilities that a Transmission Service Provider uses to
provide transmission service. In addition Clark does not perceive any reliability benefits to a TOP that
does not operate facilities that are not part of a Flowgate or transfer path; does not have a monitored
Facility of a permanent Flowgate in the Eastern Interconnection, a major transfer path within the
Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating
Limit (IROL). Clark is a TOP that does not have any need to calculate AFC, ATC, TFC, TTC, CBM, or
TRM values and believes other similar TOPs should be excluded from the applicability of the standard.
Below is the Applicability language for the Project 2012-05 ATC Revisions (MOD A) - MOD-001-2.
Clark is proposing Exemptions 4.2.2 and 4.2.3. Applicability: 4.1. Functional Entity 4.1.1 Transmission
Operator 4.1.2 Transmission Service Provider 4.2. Exemptions: The following is exempt from MOD001-2. 4.2.1 Functional Entities operating within ERCOT 4.2.2 A Transmission Operator that does not
operate facilities that a Transmission Service Provider uses to provide transmission service. 4.2.3 A
Transmission Operator that operates facilities that are not part of a Flowgate or transfer path: does
not contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major
transfer path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or
Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability
Operating Limit (IROL). Clark intends to change its ballots from negative to affirmative if the
proposed language above or other comparable changes are made to ensure that the MOD-001-2
Reliability Standard is not applicable to TOPs that are not used by TSP to provide transmission service
and are not operating facilities that are monitored elements on Flowgate or major transformer paths
as noted above.
Individual
John Bee
Exelon and its' affiliates
Yes
As NERC representatives pointed out in recent webinars, one goal of many of the existing standard
development projects is to seek a steady state for applicable standards. In order to avoid iterative
development projects, the SARs should accommodate all known issues and/or recommendations. The
recently issued Independent Experts Review Project cites a number of MOD requirements for
attention. The scope of the SAR should include assessment and resolution of the Independent Expert
Review Report recommendations. Additionally, to the extent related, the recently submitted risk
assessment by the RISC should be considered when developing the scope of SARs. Further, for any
MOD standards that require actions associated with a designated PC must accommodate the situation
in which a PC is not named. While this issue is known and under consideration within the impacted
Regions, the SAR should acknowledge this compliance gap and enable development of exemption
language or other means to avoid an inappropriate compliance obligation. Exelon supports the
concept of developing Compliance Guidance concurrently with the Standard development because it
makes sense to develop audit explanations and tools while the intent and information is fresh and
under development. In addition, this is very useful for Registered Entities to understand how
compliance will be judged. However, it is not clear how development of Compliance Input is to be
conducted. The Compliance Input should evolve as the Standard language evolves through the
standards development process and must ultimately reflect the actual language in the final, approved

standard. Understanding that no ballot is associated with Compliance Input, it would be very useful
for NERC to post Compliance Input with a separate comment form for stakeholder input. Some of the
project SARs cite development of an RSAW. Stakeholder Review and comment on RSAWs and
Compliance Input prior to the final ballot of a proposed standard will be mutually beneficial.
No
Exelon supports the draft team’s judgment in removing LSE applicable from MOD-001-2.
Individual
Long Duong
Public Utility District #1 of Snohomish County
No
No
Snohomish supports the Project 2012-05 ATC Revisions (MOD A) Standard Drafting Team in its efforts
to combine and clarify the family of MOD Reliability Standards that address transmission and its
associated margins, methodologies, and related factors. However Snohomish is concerned with the
“if” language in R1 and will be voting negative. Snohomish cannot identify any reliability benefits in
applying MOD-001-2 to a TOP that does not operate facilities that a Transmission Service Provider
uses to provide transmission service. In addition Snohomish does not perceive any reliability benefits
to a TOP that does not operate facilities that are not part of a Flowgate or transfer path: does not
contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major transfer
path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec
Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating
Limit (IROL). Below is the Applicability language for the Project 2012-05 ATC Revisions (MOD A) MOD-001-2. Snohomish is proposing Exemptions 4.2.2 and 4.2.3. Applicability: 4.1. Functional Entity
4.1.1 Transmission Operator 4.1.2 Transmission Service Provider 4.2. Exemptions: The following is
exempt from MOD-001-2. 4.2.1 Functional Entities operating within ERCOT 4.2.2 A Transmission
Operator that does not operate facilities that a Transmission Service Provider uses to provide
transmission service. 4.2.3 A Transmission Operator that operates facilities that are not part of a
Flowgate or transfer path: does not contain a monitored Facility of a permanent Flowgate in the
Eastern Interconnection, a major transfer path within the Western Interconnection, or a comparable
monitored Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included
in an Interconnection Reliability Operating Limit (IROL). Snohomish intents to change its ballots from
negative to affirmative if the proposed language above or other comparable changes are made to
ensure that the MOD-001-2 Reliability Standard is not applicable to TOPs that are not used by TSP to
provide transmission service and are not operating facilities that are monitored elements on Flowgate
or major transformer paths as noted above. Thank you for the opportunity to provide comments.
Individual
Melissa Kurtz
US Army Corps of Engineers
Agree
Florida Municipal Power Agency
Group
BC Hydro and Power Authority
Patricia Robertson
No
No
R3: BC Hydro votes Negative, see comments below. R5: BC Hydro votes Negative, see comments

below. R3 Comments: R3 seems to say if a TSP does not use CBM, the TSP is still required to keep
current a CBCID. On the other hand, M3 seems to indicate that evidence of CBMID is required only if
the TSP uses CBM. M3 is a better approach. If a TSP does not use CBM, it can simply state in its
ATCID that the CBM value is zero; it does not make sense to keep current a CBMID in this case since
the TSP is responsible for both ATCID and CBMID. No one would need to review the TSP’s CBMID to
confirm that the CBM value is zero. Unlike R4, TRMID is the responsibility of the TO who could be a
different organization from its associated TSP. The requirement for keeping current a TRMID may be
reasonable even if the TO does not use TRM. R5 Comments: R5.2.1. CBMID should be changed to
TRMID R5.3.2. TRMID should be changed to CBMID
Group
seattle city light
paul haase
Agree
Snohomish PUD
Individual
Michael Falvo
Independent Electricity System Operator
Yes
We question the need to ask this question when the consolidated standard is already posted for
commenting and balloting. The intent of posting a SAR for comment is to seek industry’s input on the
need and scope of a proposed standard development/revision project. Posting the standard for
balloting at the same time suggests that there is already a foregone conclusion on the need and the
scope for this project , and that the industry’s input on SAR would seem irrelevant. The IESO
understands that posting a SAR and the draft standards for comment at the same time can improve
standard development efficiency, and we support it to the extent that sufficient technical information
has been obtained to facilitate the development of a draft standard at the informal outreach stage.
However, we are very concerned about the fact that the industry was asked to ballot the draft
standard when the need and scope of the draft standard have not been commented on and supported
by the industry, and the standard itself has not been drafted by a formal standard drafting team.
Such an approach appears to: a. Deviates from the normal standards development process as
presented in the Standards Process Manual (SPM); b. Contradicts and perhaps violates the intent of
the established standard development process and ANSI principles to have new and revised standard
formally developed through an open and inclusive process before being presented to the RBB for
balloting. The industry is being asked to ballot a set of standards that has not been formally
developed. This concept appears to be fundamentally flawed. We propose that the SDT convey our
concern to the NERC senior management and the Standards Committee. We further suggest that
NERC and the SC evaluate alternative approaches or make revisions to the SPM to provide the needed
flexibility that can further improve the efficiency in standard development if certain elements in the
existing SPM are assessed to restrict such improvements. Notwithstanding the above, we agree with
the general direction and the scope of revisions proposed in the SAR. However, there is apparently a
lack of coordination with other standard setting organizations (eg. NAESB) to ensure the proposed
retirements are properly managed and that parallel standard development activities will take place to
implement standard changes at the same time. The SAR states that part of the objective is to retire
market-based requirements, which we support; but the SAR is silent on any details which provide
specificity on the scope of the proposed retirements, or transfer of the retired requirements to other
standard setting organizations. The mapping document does not provide specific recommendations on
which retired requirements are to be transferred to NAESB or other standard setting organizations.
From the available documents and based on our knowledge of the current activities, NAESB has not
been engaged in providing inputs on the proposed retirement, nor does it have any work plan to
implement any or all of the proposed retired requirements.
(1) We do not agree with the purpose statement as presented as it contains an unclear objective. The
purpose statement starts off with “To ensure the reliable calculation of Total Flowgate Capability (TFC)
and Total Transfer Capability (TTC) values…”. We do not think it appropriate to have an objective of

“reliable calculation” in a NERC Reliability Standard; rather, we would see a need for a Reliability
Standard having an objective to calculate TTC and ATC whose values provide a reliability basis for
transmission service reservation and utilization. We therefore suggest the purpose statement be
revised as follows: Purpose: (1) To ensure the calculated values of Total Flowgate Capability (TFC)
and Total Transfer Capability (TTC) provide a reliability basis when those values are used by a
Transmission Service Provider to calculate Available Flowgate Capability (AFC) or Available Transfer
Capability (ATC) or used by a Reliability Coordinator; (2)…. Further, Items (2) an d(3) in the purpose
statement are not objectives or desired outcome, they are actions or requirements. We suggest that
(2) and (3) be reworded and combined as follows: To ensure sharing of information on the
methodology and calculated values of TFC, TTC, AFC, ATC, Capacity Benefit Margin (CBM), and
Transmission Reliability Margin (TRM) with entities having a reliability need for the information. (2)
Part 1.1: It is unclear to us what the “this” in “A description of how this is accomplished;” means. Is it
the Statement required in Part 1.1, or is it the methodology or the incorporation of facility ratings,
voltage limits, and stability limits pre- and post-contingency. The is unclear and can lead to a
Responsible Entity unable to meet standard requirements. (3) R3: The second part is not required. If
a TSP does not use CBM, then there is not a need to the TSP to have a CBMID on which the TSP
states that it doesn’t use CBM. This exclusion can be stated in the Applicability Section, or in the
Measures. (4) R4: Same comment as in (4), above, except this is for TRM. (5) R5: The main
requirement stipulates that: “Within 30 calendar days of receiving a written request that references
this requirement…”, it is unclear whether “this requirement” means R5, and if so, it would be clearer
to just say Requirement R5. Also, do the requesting entities need to reference R5 to substantiate a
request? If, what is the rationale behind having to make this reference when the latter part of the
requirement addresses the alternative scenarios in which such a reference is not required? (6) R5,
Parts 5.2 and 5.3: According to R3 and R4, the TSP is required to develop a CBMID whereas the TOP
is required to develop a TRMID. However, Parts 5.2 and 5.3 require that the TOP provide the CBMID
and the TSP provide the TRMID upon requests. The responsibilities of the TOP and the TSP seem to be
incorrect in meeting the requests. (7) M5: Requirement R5 holds the TOP and TSP responsible for
responding to requests for information. However, Measure M5 only lists the examples of evidence that
the TSP needs to provide, but not the TOP. There is thus no Measure for the TOP to aid its provision
of evidence to demonstrate compliance. We suspect this is an oversight. (8) R6: the same comment
wrt making a reference to “this requirement” as provided under (8) above. (9) R6, Part 6.1: This part
appears to be a requirement for the requesters, but the part is not written in that fashion. To avoid
being interpreted as a requirement for the requester, we suggest to revise the main requirement R6
as follows: R6. Within 30 days of a written request that references this requirement from another
Transmission Service Provider or Transmission Operator that specify that the data is for use in the
requesting party’s AFC, ATC, TFC, or TTC calculations, a Transmission Service Provider or
Transmission Operator shall share data used in their respective AFC, ATC, TFC, or TTC calculations
(subject to confidentiality, regulatory, or security requirements). The proposed change will turn an
apparent requirement for the requesters into a condition for a valid request. (10) R6, Part 6.2: This is
not a requirement, but a provision for the TSP and TOP to not having to do anything extra. We do not
see the need for having this part to anticipate that there will be requests for data in a format that is
different than the one a TSP or TOP uses, maintains, or currently makes available to others. If the
SADT really wants to relieve the burden of the TSP and TOP form having to change the data format
when such requests are made, the SDT may want to insert a few words such as “in the format that is
currently used, maintained or made available” prior to “in their respective…” in the main requirement.
(11) The proposed effective date may conflict with Ontario regulatory practice with respect to the
effective date of the standard. Note that there is an approval requirement in Ontario for NERC
Reliability Standards. The wording presented in the Effective Dates Section does not reflect this. It is
suggested that this conflict be removed by moving the wording: “,or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities” to immediately after
“applicable regulatory approval” in Item 1 of the Effective Dates Section. This proposed wording
change also applies to the Effective Dates Section in the Implementation Plan.
Group
SERC Planning Standards Subcommittee (PSS)
Jim Kelley
No

Yes
The SDT is requested to review MOD-30-2, to incorporate the intent found in 5.3: For external
Flowgates, identified in R2.1.4, use the AFC provided by the Transmission Service Provider that
calculates AFC for that Flowgate Further request the SDT review the draft standard to ensure that the
neighboring entity’s flowgates are not placed in an oversubscribed position due to overselling
transmission service.
Request the SDT to add a sentence to 1.3. The methodologies shall include any reliability-related
constraints that are requested to be included by another Transmission Operator, provided the
constraints are also used in that Transmission Operator’s TFC or TTC calculation. This will ensure that
the facility owners reliability needs through TRM and CBM will be protected and used in any other
entity’s purchase or selling of ATC. The comments expressed herein represent a consensus of the
views of the above named members of the SERC PSS only and should not be construed as the
position of the SERC Reliability Corporation, or its board or its officers.
Group
Hydro One Networks Inc.
Sasa maljukan
Agree
The NPCC Regional Standards Committee (RSC) In addition to NPCC RSC comments Hydro One
believes that there is a clear violation of the SPM because the standards is balloted at the same time
the SAR is posted. Because of we’ll be voting casting Negative vote in this project.
Individual
Brett Holland
Kansas City Power & Light
Agree
Florida Municipal Power Agency
Group
Florida Municipal Power Agency
Frank Gaffney
No
No
FMPA is very appreciative of the efforts of the ad hoc team in boiling down the MOD standards to its
essentials. In general, FMPA is in favor of the approach of the standard. There is only one significant
issue that is causing FMPA to vote Negative (and one significant typo). The calculation of TTC/TFC and
TRM ought to be the responsibility of the TSP, not the TOP. Hence, R1 and R4 ought to apply to the
TSP, not the TOP. The only applicability to the TOP within the standard ought to be provision of data
required to assist the TSP in calculating TTC, such as models and SOLs. FMPA believes that TTC/TFC
and TRM are commercial values that may be indicative of reliability limits, but are strictly commercial
in nature. Nowhere in the standards does it require RCs or TOPs to operate to TTC/TFC; the
requirements are for RCs and TOPs to operate to SOLs and IROLs. Hence, it is FMPA’s opinion that
ultimately all of the TTC/TFC, ATC/AFC, CBM and TRM calculation requirements should be within
NAESB standards as business practices with appropriate integration between NERC and NAESB
standards similar in nature to IRO-006 (NERC) and WEQ-008 (NAESB) regarding Transmission
Loading Relief. However, FMPA also recognizes that modifications to the NAESB standards are
probably required before these MOD standards can be completely retired and we recognize the need
for a transitional step. In the meantime and in any event, TTC/TFC, ATC/AFC, CBM and TRM
calculation requirements should all be the responsibility of TSPs, not TOPs. FMPA believes that
TTC/TFC are commercial values whereas SOLs and IROLs are reliability values. SOLs and IROLs are
what the RCs and TOPs operate to. The TSP should not allow TTCs to exceed SOLs (already reflected
in the proposed R1, bullet 1.1); but, with that recognition, TTCs are indicative of SOLs, not

synonymous. An analogy might help. As far as we understand it, to reliably operate an airplane, the
airline is concerned about weight and distribution of weight within the plane. So, the operating limits
are those weight limits which are analogous to SOLs. Airlines transact within these limits by selling a
certain number of tickets and scheduling a certain amount of cargo, so, TTC/TFC is analogous to the
number of seats in a plane and amount of cargo space available; ATC/AFC is analogous to the number
of seats not sold yet and cargo space not sold yet; TRM and CBM are analogous to “safety” factors
between the expected weight and the design limits; but, it is the actual weight (of the passengers,
luggage, fuel and cargo) that is operated to against the design limits of the plane. The tickets and
cargo space to be sold are commercial in nature. If the weight is too much, the airline will cancel
certain cargo scheduled for that plane, similar to a TLR procedure. So, by way of analogy, the TOP
should tell the TSP what the maximum product is available for sale (SOLs, IROLs) and the TSP ought
to be subject to business practices to: 1) make sure that the volume of product they sell does not
exceed the maximum (i.e., that TTCs do not exceed SOLs as already included in R1, bullet 1.1); and
2) maintain contractual commitments while minimizing oversubscribtion and minimizing curtailment
through TRM, CBM and ATC/AFC calculations. At minimum, any NERC requirements regarding the
TTC/TFC and TRM calculations should be imposed on the TSP. FMPA understands that most entities
who are TOPs are also TSPs; and hence, whether the TOP or TSP does the TTC/TFC and TRM
calculations may be a moot issue for them. However, many FMPA members are TOPs (several for only
one substation that only serves that member’s load) without being TSPs and are currently required to
calculate a TTC/TFC and TRM that is never used by anyone, a wasted administrative and software
expense required only because of the way the existing MOD standards are applicable to TOPs. FMPA
suspects this is true throughout many non-RTO areas with small TOPs. The proposed standard tries to
alleviate this issue by reducing the applicability of R1 to a TOP that calculates a TTC/TFC “used by
that TOP”, requested by its TSP, or requested by its RC. However, FMPA does not believe there is
enough clarity to make it clear to an auditor that a TOP that is not a TSP does not “use” TTC. For
instance, let’s say that a fictional Global Electric Utility (“Global”) is a large verticaly intergrated utility
that is both a TOP and TSP and Global has a small utility, Village Electric Utility (“Village”), connected
to it. Village is a TOP but not a TSP and does not have an OATT. For the interface between Global and
Village, Global will calculate TTC and have an ATC path to Village. Village is not a TSP, does not have
a corresponding ATC path for its “side” of the interface, and does not need to calculate TTC. So, does
Village “use” the TTC for the ATC path within the meaning of the first bullet of R1? Although Village
does not use the TTC as an input to calculating ATC, Village does use the ATC path as a transmission
customer to Global. Would an auditor interpret this “use” as customer as triggering R1 applicability to
Village? Assigning TTC/TFC and TRM calculations to the TOP also causes implementation challenges
and conflicts with other regulations. For instance, FERC Regulations 18 CFR §§ 37.6(b)(2) states: “(2)
Calculation methods, availability of information, and requests. (i) Information used to calculate any
posting of ATC and TTC/TFC must be dated and time-stamped and all calculations shall be performed
according to consistently applied methodologies referenced in the Transmission Provider's
transmission tariff and shall be based on Commission-approved Reliability Standards as well as
current industry practices, standards and criteria.” If a TSP has more than one TOP within it, how can
a TSP ensure that the calculation of TTC/TFC is “performed to consistently applied methodologies
referenced in the Transmission Provider’s transmission tariff”? In other words, how can one TSP with
multiple TOPs ensure the TTC/TFC methodologies are consistent? FERC Regulations 18 CFR §§
37.6(b)(2) continues with: “(ii) On request, the Responsible Party must make all data used to
calculate ATC, TTC, CBM, and TRM for any constrained posted paths publicly available (including the
limiting element(s) and the cause of the limit ( e.g. , thermal, voltage, stability), as well as load
forecast assumptions) in electronic form within one week of the posting.” How can a TOP that is not a
TSP post anything? They will not have an OASIS. FERC Regulations 18 CFR §§ 37.6(b)(3)(i)(C)(3)
continues with: “(3) When the monthly and yearly capability posted under paragraphs (b)(3)(i)(A)
and (B) of this section are updated because of a change in TTC/TFC by more than 10 percent, the
Transmission Provider shall post a brief, but specific, narrative explanation of the reason for the
update.” Most of this regulation presumes that an OASIS site is being utilized; however, a TOP that is
not a TSP will not have an OASIS site. Also, Order 782 that approved revisions to MOD-028 et.al., P
15-16, discusses potential market related concerns with the additional flexibility afforded to TOPs
calculating TTC under the revised standard. FERC dismisses that concern by accepting NERC’s
arguments that entities will implement MOD-028-2 consistent with OATT legal obligations and
Commission market oversight authority. Specifically, FERC found that the potential for TTC
calculations to skew ATC values can be “mitigated through complaints and market oversight

authority”. In addition, ”transmission operators must implement the revised Reliability Standard
MOD-028-2 in a manner consistent with their existing legal obligations, including their obligations
under their open access transmission tariffs.” However, small TOPs that are not TSPs will not have a
pro forma OATT. Thus, the various Orders and regulations make more sense, and operate more
coherently if TTC/TFC calculations are conducted under the auspices of an OATT. This intent can best
be achieved by making the TSP responsible for calculating all of the values used in provision of
transmission service – TTC/TFC, TRM, CBM and ATC/AFC – and not the split of responsibilities
identified in the draft standard. Nor is reliability advanced by making TOPs that are not TSPs
responsible for TTC/TFC and TRM calculations. FMPA is aware that some regions may actually operate
to TTC/TFC rather than SOLs/IROLs (e.g., WECC). For those regions, a Variance or Regional Standard
may be appropriate. However, those regions should not cause the rest of the continent to become out
of alignment with the Code of Federal Regulations and FERC Orders. The intent of the standards is for
TOPs to operate to SOLs and IROLs, while TSPs handle the commercial matters of selling
transmission. As such, FMPA believes that the TSP should calculate TTC/TFC/TRM; however, if the
SDT does not take FMPA’s recommendation and decides to retain the TOP as the applicable entity,
then the Applicability to TOPs, Section 4.1.1, should be changed to: “Transmission Operator required
by contract with a Transmision Service Provider to calculate TTC/TFC or TRM used by that
Transmision Service Provider for purpose of calculating ATC/AFC”. A significant typo: the proposed
standard makes TSPs responsible for CBM and TOPs responsible for TRM (which, as discussed above,
we believe should be the TSP); however, R5 reverses this in bullets 5.2.1 and 5.3.2, making the TOP
responsible for the CBMID, and the TSP responsible for the TRMID.
Individual
Donald Weaver
New Brunswick System Operator
Agree
NPCC Reliability Standards committee
Individual
Kathleen Goodman
ISO New England Inc.
Agree
ISO/RTO Council Standards Review Committee (SRC)
Individual
Michael Moltane
ITC

R6.2 is really not a distinct requirement and the verbage should be included as a 2nd sentence in
R6.1. Further, R6.1 does not need to be separate but should be included at the end of R6. I.e., add
the language in R6.1 and R6.2 at the end of R6.
Individual
Diane Barney
New York State Dept of Public Service/NARUC

It is premature to be voting at all for the standard at this point in the process. Two major pieced of
information are missing. First, the SAR has not been adopted, so we do not know if the proposed
standard conforms to an adopted SAR. Second, the proposed standard was drafted by a small team of
subject matter experts and has not yet been subject to a NERC wide critical review. Therefore, we do
not yet know if there is a fatal flaw in the standard for some system(s) across NERC not represented
by the SMEs, or if there is an outstanding idea to improve the draft the standard.
Individual

Nazra Gladu
Manitoba Hydro
No

(1) Rational for R1 - for clarity, add the words [TFC and TTC] before the word “values” in the
following sentence, “Having a current and accurate description of this process allows neighboring
systems and their Transmission Service Provider to understand how the [TFC and TTC] values were
determined.”. (2) M1, Rational for R6, 1.2 Evidence Retention, VSL R5, VSL R6 - for clarity, consider
replacing the word “entity” with [registered entity] in the above sections of the standard. (3) Purpose
- consider inserting the acronyms [TSP, RC and TOP] following “Transmission Service Provider”,
“Reliability Coordinator” and “Transmission Operator” in this section. Furthermore, replace all other
instances of these words with their acronyms throughout the rest of the standard. (4) Implementation
Plan - replace the words “Board of Trustee approval” with “Board of Trustees’ approval” for
consistency with the Effective Dates section of the document. (5) General Comment - replace “Board
of Trustees” with “Board of Trustees’” throughout the applicable documents/standards for consistency
with other standards. (6) A. 3. Purpose – there is a reference in (1) to ‘…or used by a Reliability
Coordinator’, however there is no indication as to what the Reliability Coordinator would use the
information for. References in the other requirements indicate that only that the Reliability
Coordinator may request this information, but do not indicate the use by the Reliability Coordinator in
performing calculations governed by this standard. On the other hand, Transmission Operators are
not mentioned in the purpose statement, but there are repeated requirements in the standard that
relate to Transmission Operators and their use of these methodologies. Moreover, references are
made in the purpose statement (and throughout the standard) to ‘entities with a reliability need for
the information’. Is this need to be determined at the functional entity’s discretion? There is no
guidance given as to how this need is to be determined or what information would be relevant in
assessing whether a reliability need had been demonstrated adequately to meet this. (7) A, 4.2 –
ERCOT should be defined. (8) R1, R2, R3 and R4 – each of these requirements require that the
functional entity ‘keep current’ their methodologies. However, there is no guidance given as to how
that process will be assessed. Do functional entities need to be updated immediately upon any change
and/or immediately upon any change requested by another entity? or would it be acceptable to
update on some periodic basis, i.e. monthly, bimonthly, etc? (9) R1 – reviewing the rationale for R1,
it suggests that TFC and TTC values are only important when they are used to determine AFC and
ATC or in the real time operations of the transmission system. However, R1 indicates that a TO must
prepare, keep current and implement such a methodology if requested by the TSP or its RC. Please
clarify that the intent is that if requested, the TO must start using such a methodology even if they
hadn’t already been using it for calculating TFC and TTC? (10) R1, 1.3 – there doesn’t appear to be
any ability for the TO to refuse the request from another TO to include certain constraints in their
methodology. The way the requirement reads, if requested, it must be included. Please clarify if this is
the case. (11) R1, 1.4 – Manitoba Hydro suggests that this statement be modified to first include a
requirement that the methodology be provided to the TSP by the TO, before it addresses the
periodicity of the provision. (12) M1, M2, M3 – the requirements don’t contemplate publishing and
posting the information online, whereas the measures indicate that this would be an example of
evidence. For example, R5 would suggest that it need not be posted or published, but this is not clear
in the earlier Measures. Please clarify. (13) R3 – this requirement suggests that even if the functional
entity does not use CBM, they would still be required to prepare, keep current and implement a
CBMID. Would it be acceptable for the CBMID to only include a statement that CBM is not used, or is
something more required? The same comment applies for R4. (14) R5, R6 – Manitoba Hydro believes
that the SME’s should confirm that the 30 calendar day timeline is realistic for providing the
information set out in the requirement. (15) R5, R6 – the requirement to provide the data is subject
to confidentiality, security and regulatory requirements. Presumably these are confidentiality, security
and regulatory requirements of the TSP or TO, and the determination of whether such requirements
apply will be at their discretion/opinion. (16) M5 – It would seem that requirement R5 applies to both
TSPs and TOs, but the measure only refers to TSPs response to a request, not a TOs. (17) R6 –
Manitoba Hydro suggests modifying the language to include the words ‘provided that’ at the end of
the opening paragraph before 6.1 and 6.2 as 6.1 and 6.2 are actually qualifiers to the requirement in

R6 and it should be written so that they are read together. (18) M6 – the measure refers to a case
where the data request may be for data provided on an interval basis. Manitoba Hydro believes that
this isn’t actually contemplated by the requirement itself which only refers to a 30 day timeline for
providing data. (19) Compliance, 1.2 – some clarity as to what’s included in the ‘other components of
implementation and methodology documents’ is needed in this section. (20) VSLs, R1 – it’s unclear
whether these are referring to the requirement elements that are set out in 1.1 or 1.2 or 1.3 or all of
them.
Group
Puget Sound Energy
Pete Jones
No
Yes
In reference to R 1.1 of the new standard - The standard as written asks that each Transmission
Operator shall prepare a TTC methodology and include a “rationale for the selection of the TTC
method being used.” Relative to compliance enforcement, this language seems vague, especially
when compared to the existing standards. With the existing TTC methodology standards (MOD-028, 029, and -030), it is fairly clear as to what methods of TTC analysis are acceptable and how an
auditor would gauge compliance (e.g. contingency list, stability impacts, ATCID modeling criteria,
etc.). If the intent is that the Transmission Operator is expected to utilize an existing approved
method for TTC determination (all or parts of Area Interchange, Rated System Path, Flowgate), it
should be made clear in the standard. In short, how would an auditor verify a TTC methodology
rationale as being sufficient for TO/TSP compliance?
In reference to R 1.3.1 of the new standard - With respect to distribution factors, the draft standard
states that the “TO shall use . . . PTDF or OTDF of five percent or less when determining if . . .
constraints should be monitored.” As a threshold measure of statistical significance, the PTDF/OTDF is
better expressed as a minimum value to warrant monitoring a particular outage/contingency. (i.e.
“PTDF/OTDF values of 5 percent or greater should be considered when determining if constraints
should be monitored.”) It is less confusing that way (see MOD-030-1, R 2.1.4.1). Also, we suggest
giving the Transmission Operator the option of including any distribution factors below the minimum
as desired (see MOD-030-1, R 2.1.4.1). Further, as R 1.3.1 is under R 1.3, can we assume that this
PTDF/OTDF threshold of 5 percent applies only to those constraints that are requested by another TO
(R 1.3)? If so, this could be made clearer in R 1.3.1
Group
Oklahoma Gas and Electric Co.
Donald Hargrove
No
No
We thank the ad hoc team for their effort in reviewing and proposing a consolidated standard
covering the ATC process. The resulting product provides a solid basis for further work in this area. In
the RTO/Regional Tariff environment TTC/TFC, ATC/AFC, CBM and TRM calculation requirements are
all the responsibility of the TSP, not TOPs. The Transmission Owners supply their Facility Ratings and
contractual limits to the TSP who then performs the TTC/TFC, ATC/AFC, CBM and TRM calculation.
Also, we suggest removing the TOP from the applicability section 4.1.1, and change the responsibility
from the TOP to the TSP in requirements R1, R4, and R5. We recognize that this change would also
require conforming changes to the NERC Functional Reliability Model responsibilities of the TOP and
TSP. Finally, it appears that TRMID should be listed in section R5.2 and CBMID should be listed in
section R5.3. However, we recommend that the posting of (or providing of) all four (4)
methodologies/identification documents be the responsibility of the TSP to more accurately reflect
who performs these functions in an RTO/Regional Tariff environment.

Group
ISO/RTO Standards Review Committee
Greg Campoli
Yes
The SRC supports the basic concept of combining standards into coherent groups where such
grouping adds clarity and efficiency. And if this were to be a reliability standard the SRC would prefer
the proposed PRO FORMA approach suggested in this posting than the current detailed set of HOW TO
standards. However, there is a basic issue that deserves more focus than is being provided by this
abridged version of the SPM (i.e. posting SAR, Standard and simultaneously Balloting a request). In
this case the basic issue is not combining some displaced requirements; the issue is “What belongs to
NERC and what belongs to NAESB?” This critical discussion has the potential of being overlooked if the
posting is passed on the first ballot. The SRC suggests that the drafting team poll the industry to
identify those requirements that should be removed as NERC reliability standards and should either
be addressed in other venues or be deleted per the criteria used in the Paragragh 81 project. There
are people who believe that ‘transfer capacities” are market issues (SOLs and IROLs being the
reliability side of that position). FERC supports the concept that NERC address reliability and that
NAESB address Business Practices. The Industry must weigh in on this discussion. Regarding the
specific scope posted with this SAR, the SRC must note that the completed posted FORM does not
provide the “answers” required by the SAR INFORMATION section. To the question “of Industry Need
(what is the problem)”, the posting states that the Industry need is to resolve FERC directives and to
include other administrative information. The SRC does not believe that that answer is responsive to
the question. The SRC would ask that the answer respond to the which reliability problem is being
resolved. Regarding the Purpose or Goal (How does the request propose to address the above
problem), the posting states it will consolidate reliability requirements and retire market-based
requirements. Because the need statement is defined in terms of directives and not in terms of
reliability the answer does not address the original intent of this question. The SRC would prefer that
the posting be assigned to NAESB rather than be retained and debated by NERC. Regarding the
Identification of Objectives (What SPECIFIC reliability deliverables are required to achieve the goal?)
The Posted FORM states the specific deliverables are addressing FERC directives. The SRC is not
questioning the motivation for the Project, but it is questioning whether or not the Posted Form
responses are appropriate to allow the Industry to understand what the proposal is. The brief
description states that the “pro forma standard requirements” are placed within a new version of
MOD-001. The SRC does not see where R3 MOD-004-1 (CBM), R4 MOD-008-1 (TRM), R5 MOD-028-1
(ATC), et al address reliability issues. In short, the Standards Authorization Request Form that we are
asked to comment upon does not address the text in the Form nor does it address the questions
required by the FORM. Is the Industry being asked to comment upon changes made to MOD-001-1a
or is the Industry to comment about whether and which MOD standards are reliability issues and
which should be retired, referenced to NAESB or any other actions.
No
Regarding the posted MOD-001-2 the SRC would again state this posting addresses Business
Practices and not reliability requirements. Of the posted changes to MOD-001-1a the SRC would
comment: R1.1 bullet 3 is not a reliability issue. There are already IROL and SOL requirement. R1.1.
bullet 4 is informational and not a reliability issue R1.2 bullet 1 is informational and not a reliability
issue R1.2 bullet 2 requires more details. Given the fact that additions and retirements are in constant
flux, and require the TOP to make assumptions which are dependent on conditions at that time and
not subject to a fixed rule, this bullet should be removed. R1.2 bullet 7 requires more details. Given
the fact that additions and retirements are in constant flux, requiring the TOP to make assumptions
which are dependent on conditions at that time and not subject to a fixed rule, this bullet should be
removed. M1 states that the TOP must provide a statement that “such a request has not been made”.
This appears to be a requirement for the sake of a requirement and does not address any R1
reliability requirement. R2, R3, R4, R5 and R6 are documentation requirements and as such better
belong in a category outside of mandatory reliability standards and most likely better suited to
NAESB’s Business requirements. R5, Parts 5.2 and 5.3: According to R3 and R4, the TSP is required
to develop a CBMID whereas the TOP is required to develop a TRMID. However, Part 5.1 requires that

the TOP provide the CBMID while the TSP is required to provide the TRMID upon requests. The
responsibilities of the TOP and the TSP seem to be incorrect in meeting the requests. M5:
Requirement R5 holds the TOP and TSP responsible for responding to requests for information.
However, Measure M5 only lists the examples of evidence that the TSP needs to provide, but not the
TOP. There is thus no Measure for the TOP to aid its provision of evidence to demonstrate compliance.
We suspect this is an oversight. General: 1. What is the rationale for requesting 5 year retention on
methodology documents? 2. Request greater clarification on the second sub bullet of Evidence
retention Sec. 1.2. What is by “calculations and other components of implementation” and for the
most recent 14 days, etc. What is meant by the word “values”? ATC, TFC, TTC? 3. Regarding
frequency of AFC, ATC calculations, if TSP/TOP define how often they calculate a value, what
provisions should exist to address those times when technical issues prevent one calculation iteration
to be completed? Referring to existing language regarding 175 hours for hourly.
Individual
Jonathan Appelbaum
The Uited Illuminating Company
Yes
The informal team has not provided a reliability related justification for this standard as it would apply
to ISO-NE. TTC and ATC are utilized for tariff and commercial reasons. The existing MOD standards
are administrative and a diversion of compliance monitoring resources. The proposed MOD standard
reduces the requirements but is still commercial, administrative and a diversion of resources. Order
729 was issued in Nov 2009. ISO markets and procedures were developing and there was great
concern of the transparency of the calculation to provide access to alternative enrgy sources. The
processes and procedures surrounding the planning and operation of the transmission system in ISONE has matured and are now significantly different. Transmisison is allocated in a robust market
environment. The process of allocating transmission to energy providors is performed in a market not
in an operations planning environment. There is enough a difference to warrant a fresh look at the
relevance of the concept of TTC and ATC as applied to ISO-NE.
Yes
This standard is not needed for reliability in ISO markets in the Northeast. Transmission systems are
operated to and dispatched to SOL and IROL. The use of TTC and ATC is being forced onto the ISO
and its members for reasons of national consistency and not reliability.
The Standard should be written to exempt ISO-NE and its members.This will allow an auditor to focus
on items that impact adequate reliability and not on a commercial process.
Individual
Rich Salgo
NV Energy
No
No
Some concern with the use of distribution factors in R1, 1.3. This appears to state that as long as the
PTDF or OTDF on another Transmisison Operator's system from the assessed system is 5% or lower,
the Transmission Operator can ignore the impacts on that adjacent system. This seems to imply that
a TTC value can be established which demonstrates an overload in an adjacent system, but as long as
the DF's associated with the study contingencies are lower than 5%, these overloads can be
disregarded.
Individual
Mark Westendorf
MISO

R 1.3.1 should indicate the “five percent or less” is an upper limit and read as follows: “The
Transmission Operator shall use a distribution factor (Power Transfer Distribution Factor (PTDF) or
Outage Transfer Distribution Factor (OTDF) cutoff value of five percent or less when determining if
these constraints should be monitored.” Additional comments to Requirements: R1. 1. Is this
intended to require a separate document to be posted on OASIS? 2. Section should be broken down
into SOL section for internal and external entities. This aligns with TFC and TTC definitions. Then a
second section should state that “TOP should specify assumptions used to build its powerflow models
that support TTC or ATC calculations” 3. If entities already have NERC standard about SOL, shouldn’t
the requirement just be that entity follows its SOL methodology internally and language about
consideration for external SOLs? 4. Unclear what requirements need to be included in R1 vs what
should be inside ATCID for R2. Many items included in existing ATCID documents seem like they
would be moved to a new TTC ID document. 5. Regarding R.1.3.1, language should be edited to
reflect a distribution cutoff for inclusion of a constraint. R2. 1. Not clear what information needs to be
required in an ATCID document. 2. Suggest some language around periodicity of updates for ATC
calculation similar to language in 1.4. R3: 1. Have concern with wording of requirement referencing
the EEA2. Does EOP-002 R9 address this language? 2. MISO supports the application of CBM and TRM
requirements to the Operations Planning time horizon. 3. Suggest language asking TSPs to state
frequency of updates for CBM within their CBMID R4: 1. Suggest adding language from M1 into M4
when TOP and TSP are the same entity. R6: 1. Suggest revising language to indicate TSP or TOP
should provide a response within 30 days that specifies a good faith estimate of a date when data can
be shared. This is especially true for companies that utilize heavily automated systems on a hourly
basis. Much work has to be done to establish file sharing protocols. General: 1. What is the rationale
for requesting 5 year retention on methodology documents? 2. Request greater clarification on the
second sub bullet of Evidence retention Sec. 1.2. What is by “calculations and other components of
implementation” and for the most recent 14 days, etc. What is meant by the word “values”? ATC,
TFC, TTC? 3. Regarding frequency of AFC, ATC calculations, if TSP/TOP define how often they
calculate a value, what provisions should exist to address times where technical issues prevent one
calculation iteration to be completed? Referring to existing language regarding 175 hours for hourly.
Group
Sacramento Municipal Utility District & Balancing Authority Northern California
Joe Tarantino
Yes
SMUD continues to maintain that the ATC MOD standards are not reliability driven. The Available
Transmission Capacity and the calculations of associated Total Transfer Capability, Capacity Benefit
Margin and Transmission Reliability Margin would be more appropriately incorporated into NAESB
Standards. Exisiting standards address Steady-State, Voltage and Transient Stability limitations that
adequately define acceptable operating boundaries.
No
SMUD agrees with the SDT’s approach that allows the entity to determine potential need for TRM or
CBM. However, when an entity chooses not to use CBM or TRM, requiring that entity to maintain a
CBMID or TRMID document to state that the TSP does not use CBM/TRM is an administrative burden
that provides no reliability benefit. SMUD also supports limiting applicability to only the TSP for
calculation of ATC or TTC and related functions. A TOP that doesn’t own transmission, and is not a
TSP or doesn’t offer transmission service should not be required to calculate ATC functions.
Individual
Jim Howard
Lakeland Electric
No
No

1. With the proposed standard and its functional applicability, the TOP is responsible for TRMID and
TTC methodology and the TSP is responsible for CBMID and ATCID: a. Shouldn’t R5.2.1 be R5.3.2 and
vice versa? b. For clarifications purposes, suggest modifying R1.3 to “The methodologies ….used in
THE REQUESTING Transmission Operator’s TFC or TTC calculation.” 2. The drafting team has done a
great job with consolidating the existing MOD-001, MOD-004, MOD-008, MOD-028, MOD-029 and
MOD-030 standards into one standard. LAK agrees with the approach the drafting team has taken
with the pro forma standard. However, LAK, in partial agreement with FMPA’s concern, thinks that the
TSP, not TOP, should be responsible for the calculation of TTC along with the calculation of ATC and
CBM. While LAK believes that the TSP should be responsible for calculating both TTC/TFC and
ATC/AFC, the TSP shall coordinate with the TOPs to appropriately account for certain elements (i.e.
those listed under R1.2) of the TTC/TFC calculation. Therefore, LAK recommends that the drafting
team changes the responsible party for the TTC calculation/methodology requirements from the TOP
to the TSP with an additional sub requirement that certain elements (i.e. SOL/IROLs, facility ratings,
load forecast, generation dispatch, etc.) affecting TTC calculation be provided by the appropriate TOPs
to the TSP.
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
Agree
Northeast Power Coordinating Council (NPCC) region-wide group comments
Individual
Richard Vine
California Independent System Operator
No
The California ISO has submitted comments in coordination with the ISO/RTO Council (SRC) for this
project.
No
The California ISO has submitted comments in coordination with the ISO/RTO Council (SRC) for this
project. In addition the California ISO has the following comment: CAISO agrees that TTC calculation
is a reliability issue while ATC calculation (and its formula) is more of a commercial issue based on
each TSP approved Tariff. The effort to streamline the MOD-28,29, and 30 is very beneficial. The SDT
should ensure that only the reliability-related requirements are being carried forward in the new
MOD-001-2. All the commercial aspect of ATC calculation should be put under NAESB. With regards to
R1.1. it states that the Methodologies shall include “What criteria (if any) is used to select which of
the limits, or System Operating Limits (SOLs), are relevant to the calculation;” We believe that TTC
calculation should respect and meet criteria including SOLs, but it needs to be clear that TTC does not
have to be less than or equal to SOL (as currently stated in MOD-029 R3) because there is not always
a one-to-one correlation between a TTC and SOL.
Group
ACES Standards Collaborators
Ben Engelby
Yes
(1) We are concerned that the informal development process that was originally contemplated has
gone off course. The original plan was to have an informal development team create a proposal for a
standard, who would then pass the work to a formal standard drafting team to continue the
development process. This is not what has occurred. The informal development team should not have
been appointed as the formal standard drafting team without soliciting nominations, as this creates
the perception of NERC not following the standards development process. The informal development
process should not circumvent the NERC Rules of Procedure. (2) We question the value in posting the
draft standard with the SAR. What good is the SAR posting if a standard has already been developed?

This gives the impression that the Standards Committee has already determined the need for the
standard and that stakeholders have no opportunity to influence the scope contained in the SAR
contrary to the standards development process. It seems unnecessary to comment on the SAR at this
point because it appears that it was drafted in tandem with the pro forma standard. We urge NERC to
pay close attention to its Rules of Procedure and the Standard Process Manual to avoid deviations and
setting precedent that could be challenged in the future. While we agree in principle with the
consolidation of the numerous requirements in this project, the Standards Process Manual still must
be followed.
No
(1) We remain unconvinced that there is a need for a standard on TFC, TTC, AFC, ATC, TRM and CBM.
AFC and ATC are estimates on how much transmission service is remaining in the system based on
projected system conditions at the time. Transmission service does not result in any flow on the
transmission system but only represents a right to use the system. It is constantly changing because
it is heavily dependent transmission topology, generator location and output level, and system load. It
can change drastically when transmission lines or generators trips. Furthermore, it is based off an
educated guess of which generators will supply the MWs utilizing the available capability. The bottom
line is that it is based on assumptions that never exactly in real-time operations. Therefore, there is
one certainty about AFC and ATC. The valued calculated will not match the real capability in real-time.
As a result, system operators do not consider these values in any shape or form in preparing for the
transmission system operation. TFC and TTC are redundant with FAC-013 which requires the
calculation of transfer capabilities. TRM and CBM are essentially intended to ensure that the TSP does
not sell the rights to use the transmission system beyond the capabilities of the transmission system
to serve native load and network customers. It, however, does not represent actual use and deals
only with property rights and, thus, is essentially a commercial issue. System operators can still
implement emergency energy schedules and other emergency measures to serve load if necessary.
Furthermore, TOP-002 R6 already requires the TOP to operate the transmission system to meet
unscheduled changes in system configuration and generation dispatch (at a minimum N-1
Contingency Planning) and TOP-002 R10 requires the TOP to meet all SOLs and IROLs. These
standards take into account contingency planning by the TOP, so generation is continuously adjusted
to be able to survive the next contingency. Further, several TSPs have determined that there is no
reliability need for CBM or TRM in its area and have elected to adjust the settingsto zero. Given all of
these reasons, we do not see the need to for a standard on TFC, TTC, AFC, ATC, TRM and CBM to
support reliability. (2) We disagree with R1 applying to the TOP. Traditionally, it is the TSP that would
calculate the transfer capability to be consistent with the NERC functional model. (3) The purpose
statement of the standard needs to be refined. Having three different purposes for a single standard
is confusing. We recommend reducing the purpose to be more focused and succinct. Further, the
purpose statements demonstrate the very nature of this standard is focused on commercial issues.
Disclosure and transparency are commercial issues that are better suited as business practices, not
reliability concerns. (4) Requirement R1 creates unnecessary compliance burdens as currently written.
The phrase “prepare, keep current, and implement” is ambiguous and could be interpreted in multiple
ways. First, the term “prepare” does not accurately describe the action of designing or developing a
methodology for calculating TFC or TTC. “Prepare” infers preliminary work prior to actual
development. We recommend replacing “prepare” with the word “develop.” Second, the term “keep
current” is subjective and could be interpreted differently by regional compliance auditors. Whether a
document is “current” depends on a variety of factors and is subjective. Considering that an audit is a
backward looking event that could span several years, the evidence for a particular time period may
not be the most current version. We recommend striking the “keep current” clause because it causes
unnecessary confusion. Finally, the word “implement” requires additional evidence that goes beyond
the scope of the requirement. There are numerous reliability standards that contain the word
“implement” and state that the evidence to prove compliance would be through training. We do not
believe that the drafting team intends to have training be a part of this standard. If the methodology
describes how to calculate TFC or TTC, and the calculations match the methodology, then there is
evidence that the methodology was implemented. The requirement stands on its own without the
word “implement.” We recommend striking the word “implement” because the regional compliance
auditors may ask for additional evidence, such as training records, which is not the intent of this
requirement. (5) Requirement R1, Part 1.1 and Part 1.2. The structure of the standard needs to be

revised, as the bullets generally mean “or” but these lists of elements, criteria, descriptions, and
rationale are all required (i.e., “and”). The bullets should be changed to sub-parts (e.g., 1.1.1, 1.1.2,
and so on) if each action is required. The current structure deviates from the structure of reliability
standards and should be revised accordingly. (6) Requirement R1, Part 1.2. We have concerns with
the elements that are required for the TFC or TTC calculation. The second bullet and the seventh
bullet require the inclusion of “additions and retirements.” There is no need to have the phrase
“including, but not limited to, additions and retirements.” Because transmission topology should
reflect the topology for the target period of the calculation, inclusion of the phrase “additions and
retirements” is redundant and only leads to confusion. If TFC or TTC is calculated for 13 months out,
the transmission topology should reflect the expectations of that time period and failure to remove a
retired line would not reflect the transmission topology accurately. If there is an addition to the
transmission topology, then it would be included as an existing transmission element, and if there is a
retirement, then you would not need to account for it. Further, what additional factors does the
drafting team want to be considered? The phrase “including but not limited to” infers an nonexhaustive list. If there are other specific factors, list them in the standard. The issue is similar for the
seventh bullet requiring “additions and retirements” of Generator Dispatch. These bullets could be
worded better to avoid any misunderstandings. Part 1.2 already contains specific elements for the
calculation, so there is no need to leave industry guessing as to other criteria that should be included.
This bullet is problematic and we recommending striking all language after “Transmission topology”
and after “Generator dispatch.” (7) Requirement R1, Part 1.2. We have concerns with the third bullet
and the inclusion of “projected” transmission uses. What does the SDT mean by currently approved
and projected transmission uses? Is this network service, native load, and confirm point-to-point
transmission reservations? Is it requested transmission service? Is it approved transmission service
that has yet to be confirmed by the customer? This is not clear and needs further refinement. (8)
Requirement R1, Part 1.3. We have concerns with the phrase “another Transmission Operator.” The
word “another” should be replaced with “applicable” or “adjacent” or “neighboring.” Also, What does
“shall include” mean? How does one include a constraint in a methodology? Shouldn’t it state how the
TOP will address constraints requested by another TOP? This might give the TOP flexibility to decide if
it is “neighboring”, “adjacent” or something more specific. Further refinement is needed to properly
convey the drafting team’s intent. (9) Requirement R1, Part 1.4. While we appreciate the flexibility
that the drafting team provided in the current wording, allowing the TOP to provide updated values to
the TSP, we find this requirement administrative in nature and unnecessary. Paragraph 81 applies
because this requirement fits the following criteria: it is administrative in nature, is purely
documentation or reporting, requires periodic updates, and has little, if any, value as a reliability
requirement. We recommend striking Part 1.4 in its entirety. (10) Requirements R2, R3 and R4. As
stated above, we disagree with the language “prepare, keep current, and implement.” We recommend
replacing this phrase with “develop” for the reasons previously stated. (11) Requirements R5 and R6.
These requirements are administrative in nature and unnecessary. Paragraph 81 applies because
these requirements fit the following criteria: they are administrative in nature, purely documentation
or reporting, require periodic updates, and have little, if any, value as reliability requirements. We
recommend striking Requirements R5 and R6 in their entirety. (12) Compliance Section, Part 1.2
Evidence Retention. The TOP is on an audit cycle of three years. Therefore, it should only be required
to retain documentation for its audit cycle. We request that the drafting team consider reducing the
time period to align with the practical application of an audit cycle. The regional entity will retain the
data from the previous audit and there is not a need for the registered entity to also retain the
documents. We continue to believe that the data retention period is too long and may cover time
periods that are no longer relevant. There is nothing that requires the drafting team to use this
language requiring the data retention period to match the audit period. In contradiction, section
3.1.4.2 of Appendix 4C- Compliance Monitoring and Enforcement Program of the NERC Rules of
Procedure is very clear that reliability standards may have a data retention period that is less than the
audit period. Furthermore, countless standards use other data retention periods where it makes
sense. For example, TOP-003-2 uses 90 days for one of the requirements based on the sheer volume
of the data. The bottom line question should be: “Does a five year data retention period and the
associated resources dedicating to maintaining this data for that long support reliability?” The answer
is no and, thus, it should be changed. (13) VRF and VSL Table. We disagree with the categorization of
R2, R3 and R4. As stated above, the drafting team should revise the requirements to remove
“prepare, keep current, and implement” and replace it with the word “develop.” The current VSLs
should not be measured based on these subjective thresholds that require three separate actions

within a single requirement. We also disagree with the inclusion of Requirements R5 and R6 in the
standard as they are administrative in nature and meet Paragraph 81 criteria. As stated above, we
recommend striking R5 and R6 in their entirety. (14) Thank you for the opportunity to comment.
Individual
Anthony Jablonski
ReliabilityFirst
Yes
ReliabilityFirst believes the draft MOD-001-2 standard is still too locked into AFC, ATC, TFC, TTC,
CBM, or TRM being the only way to communicate availability of transmission service to the market.
ReliabilityFirst recommends changing the title to state: “Communicating Available Transmission
System Capability to the Markets” and making adjustments throughout the standard that permit other
communications of transmission service availability to be developed.
ReliabilityFirst votes in the affirmative because the modifications to this standard further enhances
reliability by addressing the FERC directives, paragraph 81 candidates, and making the requirements
more results based while consolidating the MOD A standards (MOD-001, MOD-004, MOD-008, MOD028, MOD-029, and MOD-030) into a single standard covering the reliability-related impact of ATC
and AFC calculations. ReliabilityFirst offers the following comment for consideration: The proposal
lacks any measurement of whether the communication of availability of transmission service is
accurate. Checking that the calculations conform to a methodology does not assure accuracy.
ReliabilityFirst believes the addition of a requirement to verify that past communications of service
availability were accurate would be an improvement. Since these values are predictive, and cannot be
100% accurate, there needs to be some measure of the quality of communication or even that it was
satisfactory. For consideration, ReliabilityFirst recommends a requirement for periodic analysis of the
accuracy of the communication of transmission service availability, as it relates to the use of LMP,
TLR, Reactive Interfaces and other local line loading relief procedures.
Group
Duke Energy
Colby Bellville
Yes
In the SAR, the objectives of the proposed standard’s requirements included, address outstanding
directives from FERC Order 729, remove market based requirements, and incorporate lessons
learned. Duke Energy requests clarification on which lessons learned are being incorporated. Also,
Duke Energy requests clarification on what aspects of this project will be transferred over to NAESB.
We are unclear as to what coordination will take place with NAESB.
Yes
Duke Energy has concerns that the prescribed method for the calculation of Transfer Capabilities that
is present in the currently effective standard, has not been carried over into the proposed version of
MOD-001-2. Duke Energy understands that the proposed standard allows for more flexibility to the
entity in its Transfer Capability calculations which is favorable. However, we would suggest that the
Drafting Team consider inserting the equation for calculating the ATC into the standard to promote
some consistency between entities. Also, we feel that there needs to be some additional language or
another requirement to mimic the intent of Requirement 5.3 of the current MOD-030 standard. R 1.3
requires that we include requested flowgates from neighboring areas but there is no language like R
5.3 of the current MOD-030 that requires the use of the calculated values of the owning company for
those flowgates. This ensures that the company that has the best available information as far as the
equipment capabilities and impacts is captured in everyone’s use of that flowgate for calculating
transfer capabilities. This ensures that any limits reported in the AFC/ATC process still respect that
facilities’ owner’s reliability needs for that equipment by respecting TRM and CBM. We feel this echoes
FERC’s intention as stated in paragraph 123 of FERC Order 890 which states: “This lack of
communication and coordination between transmission providers of ATC data can also affect
reliability. As discussed above, a transmission provider could grant transmission service without being
aware of the real impact that service may have on an adjacent transmission provider’s system, thus

degrading the reliability of the interconnected system. Inaccurate ATC values can cause overselling of
transfer capability, which can lead to curtailments or transmission loading relief (TLR) actions to avoid
exceeding thermal, voltage, and/or stability limits.” We also feel that there needs to be language that
includes the intent of R2.1.3. of the current MOD-30 standard. If a facility in an entity’s Reliability
Coordinator’s Area has been subjected to an Interconnection-wide congestion management procedure
within the last 12 months and is not captured in the initial flowgate screening, it should be included in
the flowgate list. By requiring the Interconnection-wide congestion management process, the limiting
Element/Contingency has shown susceptibility to transmission impacts and should be included in the
calculation of ATC.
R1: Duke Energy suggests the rewording of Requirement 1 to read: “Each Transmission Operator
shall prepare, keep current, and implement a methodology for calculating its TFC or TTC, if:” R2:
Duke Energy suggests that the drafting team should consider inserting the equation used for the
calculation of Firm and non-Firm ATC. Also, we suggest that the elements identified in R1.2, should be
included in R2 as well. R5: Duke Energy suggests that the Drafting Team consider implementing a
mechanism where an entity can reconcile differences with a neighboring entity in their calculation of
ATC/AFC and TTC/TFC. A neighboring entity’s calculation of ATC/AFC and TTC/TFC has the potential to
negatively impact an entity’s operation. R6: Duke Energy suggests that R6.1 be reworded to state,
“To be valid, the request must specify the data and frequency for use in the requesting party’s AFC,
ATC, TFC, or TTC calculations.” We feel this change would illustrate whether or not a data request was
a one time data request, or an whether an ongoing data sharing has been established.
Individual
Bill Temple
Northeast Utilities
Not in Support of the Ballot. The requirements are administrative in nature and do not support
reliability. They also seem like they would fall under Paragraph 81 criteria.
No
No

Individual
Angela P Gaines
Portland General Electric Co
Yes
PGE thanks the drafting team for the opportunity to comment on the proposed standard. As described
in the SAR the scope is to condense MOD-001, -004, -008, -028, -029 and -030 into a single standard
that covers the reliability-related impact of Available Transfer Capability (ATC) and Available Flowgate
Capability (AFC) calculations. The consolidation of these standards into one MOD-001-2 as written
does not reorient focus on the reliability-related aspects of the standards as intended. MOD-001-2
weakens coordination between neighboring utilities by failing to provide any guidance for the proper
calculation and definitions of TFC and TTC outside of the MOD-029 -030 standards that will be retired
through this project. MOD-001-2 refers several places to “TFC or TTC Methodology”
Yes
MOD-001, -004, -008, -028, -029 and -030 considered many details of the different aspects of
determining transfer capability. Consolidating these MOD’s into this single standard loses most of the
guidance being provided by NERC that was depended on by the registered entities. If there are other
guidance documents NERC has provided in the past they should be explicitly referenced within the
new standard. MOD_A leaves the development of the methodology up to the Planning Coordinator to
develop and there is no longer any aspect of coordination between adjacent entities.
MOD_A should refine requirements from the individual standards and NERC should continue to
provide the guidance which is central to the reliability need for the calculation of ATC, TFC and TTC.
Individual
Sergio Banuelos

Tri-State Generation and Transmission, Inc.
No
No
In regards to R1, the "TTC methodology" needs to remain singular throughout the requirement,
rather than the inconsistent use of the plural "methodologies". The plural use seems to indicate that
each TOP may need to present multiple methodologies for the determination of path TTCs, rather
than the one intended over-arching TOP TTC Methodology (similar to the ATCID, for instance). The
singular "methodology" should be the consistent term throughout the requirement to avoid any
confusion.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC PSS
Group
Tennessee Valley Authority
Dennis Chastain
SERC Planning Standards Subcommittee (PSS)
Yes
TVA believes that the standards could split the required tasks between the TOp and the TSP in a way
that makes more sense and is more applicable to the tasks that TOps and TSPs are normally
responsible for. For example, it makes sense that the TOp be responsible for facility ratings and SOLs
that are used in the calculation of transfer capability. It makes sense that the method used to
calculate transfer capability and the inputs into the calculation, such as TRM, are the responsibility of
the TSP. There are numerous small TOps that don’t have an associated TSP. The standards as
presently written don’t normally apply to those smaller TOps. If the calculation of transfer capability
and the inputs into the transfer capability calculation process (other than SOLs and IROLs) were
moved to the TSPs this would remove a current source of confusion for these smaller TOps that aren’t
required to calculate transfer capability but have applicable requirements under the MOD standards.
Yes
TVA agrees with the goal of the Standard Drafting Team to decrease the number of requirements and
make the standards less confusing and less onerous. Given these goals, it is important that the
standards still ensure a relatively consistent and reliable calculation of transfer capability. TVA feels
the accurate calculation of transfer capability is a reliability issue. It is the job of the operations
planners to give the operators a system that was planned to be reliable. If the operators are given a
system that has numerous n-1 overloads planned into the system, then the operational planning
engineers did not do their job. We do not want our operators to intentionally have to handle
numerous TLRs and generation re-dispatch because of an oversold system. If the TOp and TSP
oversell the system too much, it may be difficult for the operators to maintain system reliability. A
transmission system constantly in TLR3 and TLR5 due to inaccurate calculations of transfer capability
is a reliability issue and not just a commercial issue. If your neighbor is constantly selling transfer
capability and ignoring the impact on your system, this too will affect your reliability. It is important
that the MOD standards ensure that the calculation of transfer capability is done accurately such that
the TOp and TSP are not causing reliability issues on their own system and their neighboring systems.
The language in 1.3.1 as written is confusing. It needs to be defined how the PTDFs and OTDFs are
calculated. It’s assumed that the drafting team means a generation to load impact, if so it needs to be
stated as such. The drafting team should also be careful with using the value TTC. It has many
different meanings depending on what transfer capability calculation methodology is used. TTC is
normally a useless value without much direct relationship to the system. The problem lies in the fact
that in order to calculate TTC there must be some reservation assumptions included in the model to
begin with. What assumptions are included can change what the TTC value is. A more important value

that does relate to the reliability of the system is ATC. We think the standards should revolve around
the calculation of ATC and the accurate calculation of ATC. All three methodologies use ATC and have
the same relative definition of ATC. ATC also has a direct relationship to the reliability of the system.
Group
Colorado Springs Utilities
Kaleb Brimhall
Florida Municipal Power Agency (FMPA)
No
Yes
• Please clarify PTDF and OTDF 5% threshold value in R1.3.1 to ensure it meets the intention of MOD030-2.
• TTC must not be considered the real-time SOL or IROL (TTC and SOL/IROL are completely different
flows , scheduled versus actual). TOP should honor SOL and IROLs not TTC or TRC.
Group
SPP Standards Review Group
Robert Rhodes

No
R1.2 of MOD-029-1a was omitted in the Mapping Document.
We thank the ad hoc team for their effort in reviewing and proposing a consolidated standard
covering the ATC process. The resulting product provides a solid basis for further work in this area.
Thanks to the team. We support the justification offered by the Florida Municipal Power Agency
proposing to change the responsibility of TTC/TFC and TRM calculation requirements from
Transmission Operators (TOPs) to Transmission Services Providers (TSPs). Therefore, we suggest the
following changes: • From the Applicability section remove 4.1.1 Transmission Operator. • R1, change
the responsibility from the TOP to the TSP. We recognize that this change would also require
conforming changes to the NERC Functional Reliability Model responsibilities of the TOP and TSP. The
NERC Reliability Functional Model states that the TTC/TFC calculation is the responsibility of the TOP.
• R4, change the responsibility from the TOP to the TSP. We’re also proposing conforming changes to
the TRMID definition in the NERC Glossary of Terms. The approved TRMID definition (below) in the
NERC Glossary of Terms indicates that TRM calculation is the responsibility of the TOP. The TRMID
definition should change from “…Transmission Operator’s calculation of TRM” to “…Transmission
Services Provider’s calculation of TRM.” TRMID (NERC Glossary of Terms): A document that describes
the implementation of a Transmission Reliability Margin methodology, and provides information
related to a Transmission Operator’s calculation of TRM. • R5, change the responsibilities to refer only
to the Transmission Service Provider (TSP). In the VSLs for R1 the phrase ‘one of the requirement
parts’ is used extensively. It is not clear whether this refers to R1.1 in totality or to any one of the
bulleted items under R1.1. Can the drafting team please clarify? ‘Real time’ in the Rationale Box for
R2 needs to be changed to ‘Real-time’ to be consistent with the Glossary of Terms.
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery
No
We appreciate this effort to answer FERC Order 729, while seeking to determine the proper balance
between reliability, commercial, and compliance risks.
No
So long as R1.3 includes honoring a flowgate TOP TSP's AFCs, when requested by that neighboring
TOP or its TSP, AECI believes this MOD-001-2 captures the overall intent.

We question the need for other than TSPs to be applicable to this Standard, where TOPs should be
proactive but not required to utilize provisions and transparency drafted herein. We agree this
Applicability issue, raised by other's comments, requires careful consideration, to avoid unnecessarily
burdening unrelated entities.
Group
Western Electricity Coordinating Council
Steve Rueckert

No
WECC questions the need for the standard at all. WECC voted to approve the standard becasue it is
an improvement over the existing standards. However, TTC/TFC and TRM are commercial values that
may be indicative of reliability limits, but are strictly commercial in nature. RCs and TOPs are not
required to operate with TTC limits, but rather within SOLs and IROLs. The long term goal should be
to retire this standard in its entirety but this first step is an improvement over the currently effective
standards.
Individual
Donald E Nelson
Commonwealth of MA Dept. of Public Utilities
Agree
I support the comments of NPCC.
Group
Southern Company: Southern Company Services, Inc.; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation;
Southern Company Generation and Energy Marketing
Pamela Hunter
Yes
In R5 it states “or any other registered entity that demonstrates a reliability need”. FERC in its ORDER
729 para 151 states that the reliability needs to be demonstated to the ERO. May need to make this
clearer in the requirement. R5 5.1 needs to be removed or made to be consistence with 5.2 and 5.3
R3 states “Each Transmission Service Provider shall prepare, keep current, and implement a Capacity
Benefit Margin Implementation Document (CBMID) that describes its method for establishing margins
to protect system reliability during a declared NERC Energy Emergency Alert 2 or higher.
Transmission Service Providers that do not use Capacity Benefit Margin (CBM) shall state this in the
CBMID.” A better wording of this standard would be “Each Transmission Service Provider that
maintains a CBM shall prepare, keep current, and implement a Capacity Benefit Margin
Implementation Document (CBMID) that describes its method for establishing margins to protect
system reliability during a declared NERC Energy Emergency Alert 2 or higher.” Taking out the last
sentence which is already stated in NAESB standards will eliminate the risk of double jeopardy. R4
states “Each Transmission Operator shall prepare, keep current, and implement a Transmission
Reliability Margin Implementation Document (TRMID) that describes its method for establishing
margins to protect system reliability. Transmission Operators that do not use Transmission Reliability
Margin (TRM) shall state this in the TRMID.” A better wording of this standard would be “Each
Transmission Operator that maintains a TRM shall prepare, keep current, and implement a
Transmission Reliability Margin Implementation Document (TRMID) that describes its method for
establishing margins to protect system reliability.” Taking out the last sentence which is already
stated in NAESB standards will eliminate the risk of double jeopardy.
No
In R1 does this mean a TSP can request a TOP to prepare, keep current, and implement a TTC
methodology? In M1-M4 there is no requirement to make it available, just to prepare it, keep it

current, and implement it. If no requirement to make it available, the measure should only be “A
dated effective methodology”. The “M” should say “A dated methodology that addresses, at a
minimum, the elements required in R1 and subparts.” In R2 since TTC is a component of ATC, would
it be acceptable for a TSP to refer to the TOP’s TTC Method in its ATCID?

Additional Comments Received:
Portland General Electric Co.
1. Do you have any specific questions or comments relating to the scope of the proposed standard
action or any component of the SAR outside of the pro forma standard?
Yes
No

Comments:
As described in the SAR the scope is to condense MOD-001, -004, -008, -028, -029 and -030 into a single
standard that covers the reliability-related impact of Available Transfer Capability (ATC) and Available
Flowgate Capability (AFC) calculations. The consolidation of these standards into one MOD-001-2 as
written in the SAR does not reorient focus on the reliability-related aspects of the standards as intended.
MOD-001-2 weakens coordination between neighboring utilities by failing to provide sufficient guidance
for the proper calculation and definitions of TFC and TTC outside of the MOD-029 -030 standards that
will be retired through this project. A consistent methodology would no longer exist in a controlled
document as it does today with the current MOD’s. NERC guidance will be even more important when
adjacent utilities use differing methodologies and calculate differing values at interconnection points.
2. Are there any specific elements from the original MOD-001, MOD-004, MOD-008, MOD-028, MOD029, or MOD-030 that you believe are critical to reliability that have not been retained? Please explain.
Yes
No
Comments:
Portland General Electric supports NERC’s effort to consolidate duplicative and overlapping reliability
standards, including MOD-001, -004, -008, -028, -029 and -030 which consider many details of the
different aspects for determining transfer capability. However, consolidating these MOD’s into this
single standard loses most of the guidance being provided by NERC that was depended on by the
registered entities. MOD_A leaves the development of the methodology up to the Planning Coordinator
to develop and there is no longer any aspect of coordination between adjacent entities.
3. Please specify if you have comments or proposed changes to any of the Requirements of the pro
forma standard.

Comments: MOD_A should refine requirements from the individual standards and NERC should
continue to provide the guidance which is central to the reliability need for the calculation of ATC, TFC
and TTC. PGE suggest that NERC point entities to the guidance documents NERC has provided such as
“Transmission Transfer Capability, May 1995” should be explicitly referenced as standard methodology
within the new standard

Consideration of
Comments Summary
Project 2012-05 ATC Revisions (MOD A)
October 4, 2013

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NERC | Consider of Comments Summary – Project 2012-05 ATC Revisions (MOD A)| October 4, 2013 Atlanta, GA 30326
404-446-2560 | www.nerc.com
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Table of Contents
Table of Contents ......................................................................................................................................................................... 2
Introduction ................................................................................................................................................................................. 4
Standards Authorization Request (SAR) .................................................................................................................................. 4
“Prepare, keep current, and implement” ................................................................................................................................ 4
Approach in Consolidating Standards ...................................................................................................................................... 5
Administrative Comments ....................................................................................................................................................... 5
Title .......................................................................................................................................................................................... 5
Applicability Section ................................................................................................................................................................ 5
Define ERCOT ....................................................................................................................................................................... 6
Purpose Section ....................................................................................................................................................................... 6
Mapping Document ................................................................................................................................................................. 6
NAESB Coordination ................................................................................................................................................................ 6
NERC Functional Model ........................................................................................................................................................... 6
Consideration of Comments by Requirement ............................................................................................................................. 7
Requirement R1 ....................................................................................................................................................................... 7
Rationale Section ................................................................................................................................................................. 7
Justification for Assigning the TTC or TFC Calculation to the TOP ....................................................................................... 7
TOPs that do not calculate AFC/ATC or TFC/TTC due to the Regional Transmission Organization performing the role .... 8
Revisions to Requirement R1 ............................................................................................................................................... 9
Requirement R2 ....................................................................................................................................................................... 9
Requirement R3 ..................................................................................................................................................................... 10
Measure M3....................................................................................................................................................................... 10
Requirement R4 ..................................................................................................................................................................... 10
Measure M4....................................................................................................................................................................... 11
Requirement R5 ..................................................................................................................................................................... 11
Measure M5....................................................................................................................................................................... 11
Confidentiality ................................................................................................................................................................... 12
Requirement R6 ..................................................................................................................................................................... 12
Confidentiality ................................................................................................................................................................... 12
MOD-001-2 Compliance Section Comments ............................................................................................................................. 13
Evidence Retention ............................................................................................................................................................ 13
Violation Severity Levels (VSLs) ......................................................................................................................................... 13

NERC | Consider of Comments Summary – Project 2012-05 ATC Revisions (MOD A)| October 4, 2013
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Consideration of Comments
Project 2012-05 ATC Revisions (MOD A)
Comment Form
Combined Question 1, Question 2, and Question 3 Summaries

The Project 2012-05 Drafting Team thanks all commenters who submitted comments on the draft MOD-001-2
standard. This standard was posted for a 45-day public comment period from July 11, 2013 through August 27,
2013. Stakeholders were asked to provide feedback on the standard and associated documents through a
special electronic comment form. There were 51 sets of comments, including comments from approximately
160 different people from approximately 106 companies representing all 10 of the Industry Segments as shown
in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every
comment serious consideration in this process! If you feel there has been an error or omission, you can contact
the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at [email protected]. In
addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual:
http://www.nerc.com/pa/Stand/Resources/Documents/Appendix_3A_StandardsProcessesManual.pdf

NERC | Consider of Comments Summary – Project 2012-05 ATC Revisions (MOD A)| October 4, 2013
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Introduction
The Standard Drafting Team (SDT) appreciates the industry comments on the proposed Reliability Standard
MOD-001-2 and accompanying documents, such as the implementation plan and mapping document.
Additionally, the SDT appreciates the comments in support of the proposed Reliability Standard and the
consolidation of existing Reliability Standards MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a,
and MOD-030-2 into a single Reliability Standard. Below is a summary of the comments received and a
discussion of the SDT’s response to those to those comments, including modification of the proposed Reliability
Standard, following in-depth discussion.

Standards Authorization Request (SAR)
One commenter stated that the Independent Experts recommendations should be included in the Standards
Authorization Request (SAR) and addressed by the SDT. The SDT noted that prior to posting the SAR and the
proposed Reliability Standard for ballot, an informal ad hoc group working on the MOD standards covering
Available Transfer Capability (ATC), many of whom are part of the SDT, reached out to the Independent Experts
to discuss their recommendations. The SDT considered these discussions when drafting the SAR and proposed
MOD-001-2.
Another commenter stated that the assessment and resolution of the Independent Experts Review Panel Report
should be added to the scope of the SAR. The SDT noted that the report was not presented to the NERC Board of
Trustees (Board) at the time the SAR was authorized. However, as mentioned above, the informal ad hoc group
members did interact with the Independent Expert’s during the informal development period and considered
those discussions when drafting the SAR.
Another commenter requested clarification as to the meaning of “lessons learned” in the purpose section of the
SAR. The SDT stated that those lessons learned include best practices by entities, sharing of those best practices,
compliance audit experiences, and growth and maturity of the markets.
The SAR was revised based on industry comment and submitted to the NERC Standards Committee (SC) for
approval. A redlined version of the SAR can be found on the project page.2

“Prepare, keep current, and implement”
There were several comments that the phrase “prepare, keep current, and implement” is vague and ambiguous.
The existing FERC-approved Reliability Standards use the language “prepare and keep current” to refer to the
actions entities must take with respect to various implementation documents. Based on compliance history and
lessons learned from more-than-six plus years of mandatory compliance, the word “implement” was added to
further substantiate that if a registered entity has an implementation document.
Based on these comments, the SDT considered this issue in detail and decided to modify the language in
Requirements R1, R2, R3, and R4 to clarify the performance expectation. For example, the new language in
Requirement R2 reads, “Each Transmission Service Provider that determines AFC or ATC shall develop an
Available Transfer Capability Implementation Document (ATCID) that describes the methodology (or
methodologies) it uses to determine ATC or AFC values. The methodology (or methodologies) described must
reflect the Transmission Service Provider’s current practices for determining AFC or ATC values.” The language
within Requirement R2 as shown above retains the SDT’s intent of the Requirement while removing the
ambiguous language of the phrase “prepare, keep current, and implement.” This was also carried out in
Requirements R1, R3, and R4.

2

http://www.nerc.com/pa/Stand/Pages/Project201205MODAAvailableTransferCapability.aspx

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Introduction

Approach in Consolidating Standards
One commenter stated that consolidating the MOD Reliability Standards into a single Reliability Standard loses
most of the guidance being provided by NERC. The commenter added that this new Reliability Standard no
longer calls for any aspect of coordination between adjacent entities. The SDT noted that informal development
eliminated much of the instructional detail from the existing MOD-001, MOD-004, MOD-008, MOD-028, MOD029 and MOD-030 Reliability Standards because those details provide little to no reliability benefit. Significantly,
the SDT is also actively working to have NAESB review the retiring requirements to ensure that those aspects
critical to the business aspects of Available Flowgate Capability (AFC) and Available Transfer Capability (ATC)
values are not lost. Much of the material in the existing MOD Reliability Standards was, as the commenter puts
it, “guidance”, which while helpful from a technical standpoint is not appropriate in a NERC Reliability Standard.
Additionally, a technical white paper was posted on NERC’s website that encapsulated much of the material that
was in the prior publications of NERC on the determination of Total Transfer Capability (TTC), Total Flowgate
Capability (TFC), Capacity Benefit Margin (CBM), Transmission Reliability Margin (TRM), AFC and ATC values and
in the existing Reliability Standards to ensure that the guidance currently provided by the standards and those
documents was not lost.
The SDT also revised the proposed standard to strengthen the language on coordination between registered
entities in Requirements R1.3 and R2.2 with request to reliability constraints, and captured the essence of the
material that is present in the current MOD-030 Reliability Standard. The SDT also noted that all of the other
coordination aspects from the existing Reliability Standards - such as method sharing and data sharing - are
present in the new Reliability Standard.

Administrative Comments
One commenter stated that the Reliability Standard should be consistent in its use of acronyms (i.e. ATC or AFC,
AFC or ATC). The SDT went through the standard to ensure that the use of acronyms was consistent. The SDT
also went through the standard to spell out the acronyms the first time it was is used and use the acronym for
any subsequent references.
There was a comment to use the term “registered entity” be used in place of “entity” in various components of
MOD-001-2, specifically Measure M1, rationale for Requirement R6, Part 1.2, evidence retention, and the
Violation Severity Levels (VSLs) for Requirements R5 and R6. In response, the SDT has implemented the
suggestion.

Title
A commenter stated that the Reliability Standard title should be changed to “Communicating Available
Transmission System Capability to the Markets.” In response, the SDT reasoned that this standard encompasses
more aspects of Available Transmission System Capability than just market communication.

Applicability Section
Several commenters suggested an exemption clause for smaller Transmission Operators (TOPs) that do not
operate facilities that a Transmission Service Provider (TSP) uses to provide transmission service. Furthermore,
commenters do not perceive any reliability benefits to including a TOP that (1) does not operate facilities that
are not part of a Flowgate or transfer path; (2) does not have a monitored Facility of a permanent Flowgate in
the Eastern Interconnection, a major transfer path within the Western Interconnection, or a comparable
monitored Facility in the ERCOT or Quebec Interconnections; and (3) is not a monitored Facility included in an
Interconnection Reliability Operating Limit (IROL). In response, the SDT modified Requirement R1 to make it
clear that the requirement addresses the concerns of the TOP that only calculates System Operating Limits
(SOLs) and does not calculate TTC or TFC.

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Introduction

Define ERCOT
With respect to the exemption of entities operating within the Electric Reliability Council of Texas (ERCOT), there
was a commenter who requested a definition of ERCOT. FERC Order No. 729, Paragraph 298, states “…we
believe that it is appropriate to exempt entities within ERCOT from complying with these Reliability Standards.
We agree, due to physical difference of ERCOT’s transmission system, the MOD Reliability Standards approved
herein would not provide any reliability benefit within ERCOT.” Therefore, the SDT kept functional entities
within ERCOT as the exempt registered entities. The revised Reliability Standard will spell out the acronym in the
applicability section.
Another commenter sought similar applicability exclusion for the ISO New England (ISO-NE) market. The SDT
determined that granting additional exemptions was outside the scope of its responsibility.

Purpose Section
There were several general comments with regard to the purpose section of MOD-001-2. One commenter
stated that there was a reference to the Reliability Coordinator (RC), yet there was no indication as to how or
why the RC would use the information. Based on comments, the purpose section has been modified.

Mapping Document
There was a comment that Requirement R1.2 of MOD-029-1a within the mapping document was omitted. The
SDT appreciates the commenter’s careful review of the mapping document and included that sub-requirement
in the latest revision.

NAESB Coordination
There were several comments regarding the perceived lack of coordination with the North American Energy
Standards Board (NAESB). NERC and FERC have been in contact with NAESB about the efforts during the
informal development of the MOD A project and have continued to coordinate their efforts.

NERC Functional Model
With respect to the aforementioned discussion topics of the responsibilities of the TOP and TSP, there were
several comments relating to inconsistencies between the NERC Glossary of Terms Used in Reliability Standards
and the NERC Functional Model. This is outside the scope of the SDT and this project.

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Consideration of Comments by Requirement
Requirement R1
Rationale Section
There was a comment to add the words “TFC and TTC” before the word “values” in the Rationale. In response,
the SDT has inserted the requested language. The SDT has modified the Rationales to add the commenter’s
suggestion where appropriate.
Justification for Assigning the TTC or TFC Calculation to the TOP
TFC and TTC values are important to the reliability of the Bulk-Power System (BPS) when they are used to
determine AFC and ATC or in the Real-time operation of the transmission system. The TOP needs to calculate a
TFC or TTC value that protects reliability both on its system and neighboring systems. The TOP is the registered
entity that performs such calculations, as described in Section 6 of the NERC Functional Model. Therefore, the
TFC and TTC calculation is properly assigned to the TOP. While TFC and TTC are used for commercial purposes
(i.e., AFC and ATC), their determination and calculation is reliability based. This can also be concluded from their
NERC definitions provided below.
Furthermore, the current applicability of TTC per MOD-028 and MOD-029 is with the TOP. Registered entities
have aligned their practices to conform and be compliant with the existing MOD Reliability Standards. Changing
this assignment to the TSPs would cause burdens and would be inconsistent with NERC Glossary terms and NERC
Functional Model.
Due to the TFC and TTC calculation being properly assigned to the TOP, it follows that the TRM shall also be
determined by the TOP. TRM accounts for the inherent uncertainty in system conditions and the need for
operating flexibility to ensure reliable system operation as system conditions change. Finally, it is also stated in
the NERC definition of the TRMID that this is a TOP function and not a TSP function.
Transmission Operator
The TOP operates or directs the operation of transmission facilities, and maintains local-area reliability, that is,
the reliability of the system and area for which the TOP has responsibility. The TOP achieves this by operating
the transmission system within its purview in a manner that maintains proper voltage profiles and System
Operating Limits, and honors transmission equipment limits established by the TO.
Total Transfer Capability
The amount of electric power that can be moved or transferred reliably from one area to another area of the
interconnected transmission systems by way of all transmission lines (or paths) between those areas under
specified system conditions.
Total Flowgate Capability
The maximum flow capability on a Flowgate, is not to exceed its thermal rating, or in the case of a flowgate used
to represent a specific operating constraint (such as a voltage or stability limit), is not to exceed the associated
System Operating Limit.
Transmission Reliability Margin
The amount of transmission transfer capability necessary to provide reasonable assurance that the
interconnected transmission network will be secure. TRM accounts for the inherent uncertainty in system
conditions and the need for operating flexibility to ensure reliable system operation as system conditions
change.

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Consideration of Comments by Requirement

Transmission Reliability Margin Implementation Document
A document that describes the implementation of a TRM methodology, and provides information related to a
TOP’s calculation of TRM.
The SDT had lengthy discussion about Requirement R1 and its applicability. During the discussion, the SDT
reviewed the terminology used for Transfer Capability and TTC.
1. Transfer Capability – (as defined in the NERC Glossary of Terms)
The measure of the ability of interconnected electric systems to move or transfer power in a reliable
manner from one area to another over all transmission lines (or paths) between those areas under
specified system conditions. The units of transfer capability are in terms of electric power, generally
expressed in megawatts (MW). The transfer capability from “Area A” to “Area B” is not generally equal
to the transfer capability from “Area B” to “Area A.”
2. Total Transfer Capability – (as defined in the NERC Glossary of Terms)
The amount of electric power that can be moved or transferred reliably from one area to another area of
the interconnected transmission systems by way of all transmission lines (or paths) between those areas
under specified system conditions.
The current TOP and FAC Reliability Standards require the TOP to establish and calculate SOLs that ensure
acceptable performance criteria both pre- and post-contingency. In doing so, TOPs perform power flow analyses
that reflect the expected system condition in the BPS for a specified system condition.
In a similar manner, a transfer analysis needs to be performed to ensure that the Transfer Capability and its
associated TTC are established in a manner that respects SOLs for any specified system conditions. In other
words, these transfer analyses are normally performed with the objective of establishing a TTC/TFC that
respects SOLs – not necessarily to determine the SOL itself (i.e., this analysis will simulate power system
transfers and establish a TTC/TFC that does not cause Facility Ratings, voltage limits, transient stability limits,
and voltage stability limits to be exceeded in the pre- and post-contingency state). While TTC/TFC may not
equate to an SOL itself, TTC/TFC needs to be calculated by the registered entity that is responsible for ensuring
that Facility Ratings, voltage limits, transient stability limits, and voltage stability limits are respected in the preand post-contingency state. As such, it is appropriate for the TOP to be the registered entity responsible for
determining TTC/TFC.
There is an important caveat that must be acknowledged. As noted above, transient and voltage stability limits
are calculated and expressed as pre-contingent path or interface flow values. Accordingly, transfer analyses are
required to establish the transient and voltage stability limits. It is possible that transient stability limits and
voltage stability limits may define TTC/TFC for certain paths, rendering TTC/TFC and the path’s SOL to be the
same value. Even still, the new paradigm is upheld – TTC/TFC respects the SOL.
TOPs that do not calculate AFC/ATC or TFC/TTC due to the Regional Transmission
Organization performing the role
There were several commenters who stated the TOPs should not be obligated to perform duties they do not
actually perform in practice. In response, the revised posting in Requirement R1 states, “Each Transmission
Operator that determines TFC or TTC” at the opening of the requirement, so the requirement only places an
obligation upon a TOP if they calculate TFC or TTC. The requirement does not obligate a TOP to calculate TFC or
TTC, nor does it preclude the use of a Coordinated Functional Registration for the TOP to assign the role to
another registered entity.
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Consideration of Comments by Requirement

Revisions to Requirement R1
Based on comments on Requirement R1, the SDT made several revisions to Requirement R1, as discussed below.
A number of commenters raised issues about the fourth bullet of Requirement R1, Part 1.1 of the posted
standard. There was a comment that the bullet is informational and not a reliability issue. Another commenter
suggested that this statement should be modified to first include a requirement that the methodology be
provided to the TSP by the TOP, before it addresses the periodicity of the provision. One commenter wanted
clarification on whether or not the periodicity highlighted in Requirement R1, Part 1.4 implies that any updates
to TFC or TTC should be regularly scheduled, or, provided on an as needed basis. The commenter maintained
that in the absence of significant changes to a path, requiring a specific cycle of updates is arbitrary to both
functional entities. In response, the SDT removed this provision from the proposed Reliability Standard as it does
not contain a reliability component.
One commenter requested clarification as to whether the Power Transfer Distribution Factor (PTDF) and Outage
Transfer Distribution Factor (OTDF) five percent threshold value in Requirement R1.3.1 has the same meaning as
it does in MOD-030-2. Another commenter stated that the language in Requirement R1.3.1 is confusing and that
how the PTDFs and OTDFs are calculated needs to be defined. In response, the SDT rewrote the posted portion
mentioning the PTDF and OTDF thresholds and revised the language.
There was a comment in regard to Requirement R1, Part 1.2. There was concern in the third bullet about the
inclusion of “projected” transmission uses and what the SDT meant by currently approved and projected
transmission uses. The commenter stated that this is unclear and needs further refinement. In Requirement R1,
Part 1.2, the SDT was attempting to say that the determination of TFC, TTC, AFC and ATC needs to include the
effect of expected transmission use. Depending on the system being studied, the expected transmission use may
be the full amount of reservations, or the expected use of those approved reservations. In some cases the
underlying model for TTC may even include forecasted uses that are not officially approved, due to their impact
on reliability. In order to address this, the SDT is using the phrase “expected transmission uses” to cover all of
those situations.

Requirement R2
Several commenters who use the AFC methodology expressed concerns that coordination between neighboring
TSPs was not occurring in the revised version of the Reliability Standard. The SDT discussed this concern and
agreed to add language to Requirement R2 that reflects the coordination between TSPs that calculate AFC.
Several commenters suggested adding the same language from Requirement R1 into Requirement R2 for TSPs
that calculate AFC or ATC. The language in Requirement R1 reads, “Each methodology shall describe the method
used to account for each of the following elements, provided such elements impact the determination of TFC or
TTC.” Another commenter suggested that the language was not clear as to what information is required in a
TSP’s ATCID. The SDT added language to Requirement R2 for those elements that impact the determination of
AFC or TTC.
Other commenters requested clarification on the frequency of AFC or ATC calculations of and how the technical
issues are addressed when there is a failure in the process and the calculation of AFC or ATC values does not
occur. The SDT discussed these comments and concluded that this situation should be indentified in the
registered entity’s ATCID. Therefore, the SDT did not make a change.
Some commenters suggested that the equation for calculating AFC or ATC should be included as a requirement.
The SDT considered this suggestion and noted that it is not necessary for reliability purposes to include the
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Consideration of Comments by Requirement

equation for calculating AFC or ATC in the standard. Noted, however, the equation should be included as part of
a registered entity’s ATCID and the equation for ATC is a NERC-defined term.

Requirement R3
The SDT received several comments related to Requirements R3 and R4 to maintain a CBMID or TRMID even if
the registered entity does not maintain CBM or TRM, respectively. After discussion, the SDT modified
Requirements R3 and R4 and removed the requirement to have a specific document labeled CBMID or TRMID.
Additionally, the SDT made updated Measures M3 and M4 to reference examples of evidence that may be used
to meet Requirements R3 and R4. The SDT recognizes that some TSPs do not need to exercise CBM while others
may handle transparently within their Transmission Service Requests (TSRs). However, the SDT agreed there is a
reliability benefit in TSP’s accurately documenting their application of CBM for review by their neighboring TOPs
and TSPs. The SDT thus reworded Requirement R3 to provide that CBM may be used in the AFC/ATC and when
used, to require a CBMID. When not used, a CBMID is not required.
The SDT received several comments questioning if Requirement R3 is reliability related. The proposed Reliability
Standard does not require a registered entity to use CBM; however if the registered entity uses CBM, then it
must accurately describe the current process of calculating CBM so that can be shared with other entities with a
reliability need to understand its process. The SDT concluded that the disclosure of this methodology satisfies
the reliability goal of transparency in these calculations.
One commenter stated that an Energy Emergency Alert 2 (EEA 2) or higher may be covered in EOP-002
Requirement R9. The SDT reviewed the proposed language in Requirement R3 of MOD-001-2 and discussed a
proposal to strike the language of “… to protect system reliability during a declared NERC Energy Emergency
Alert 2 or higher.” The SDT removed the language that specifically tied CBM to a particular condition. NAESB
business practice standards and other established references define and point to the use of CBM. Being
prescriptive in the NERC Reliability Standard would limit NAESB’s ability to further define the role of CBM and
create a conflict if the NERC EEA definitions are changed.
One commenter suggested adding language asking TSPs to state the frequency of updates for CBM within their
CBMID. The SDT discussed this suggestion, but came to consensus that adding such language is unnecessary
because Requirement R5 allows for entities to request clarifications of a TSP’s methodology, which may include
the frequency of update.
Measure M3
The language, “if the TSP does not maintain CBM then example of evidences include but are not limited to; an
affidavit, statement, or other document that states the TSP does not maintain CBM …” was added to Measure
M3 to clarify what evidence is necessary if the TSP does not maintain CBM.

Requirement R4
The SDT received several comments related to Requirements R3 and R4 to maintain a CBMID or TRMID even if
the registered entity does not maintain CBM or TRM, respectively. After discussion, the SDT modified
Requirements R3 and R4 and removed the requirement to have a specific document labeled CBMID or TRMID.
Additionally, the SDT made updated Measures M3 and M4 to reference examples of evidence that may be used
to meet Requirements R3 and R4. The SDT recognizes that some TSPs do not need to exercise TRM while others
may handle transparently within their TSRs. However, the SDT agreed there is a reliability benefit in TSP’s
accurately documenting their application of TRM for review by their neighboring TOPs and TSPs. The SDT thus
reworded Requirement R4 to provide that TRM may be used in the AFC/ATC and when used, to require a
TRMID. When not used, a TRMID is not required.

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Consideration of Comments by Requirement

The SDT received several comments questioning if Requirement R4 is reliability related. The proposed Reliability
Standard does not require a registered entity to use TRM; however, if the registered entity uses TRM, then it
must accurately describe the current process of calculating TRM so that it can be shared with other entities with
a reliability need to understand its process. The SDT concluded that this disclosure of methodology
simultaneously satisfies reliability requirements and the goal of transparency.
Measure M4
There was a comment that stated an example of evidence should not include a study report. In the NERC
Standards Process Manual, a measure is defined as “identification of the evidence or types of evidence that may
demonstrate compliance with the associated requirement.” In the existing MOD-004-1 Reliability Standard, the
measures include “studies” as examples of evidence. In the existing MOD-008-1 Reliability Standard, the
measures include “study reports”. The SDT struck the posted language of “such as a study report”, as the listing
of a study report as a form of evidence caused some concern within industry since not all TRM values are the
result of a study report. The SDT considered a comment made referencing Measure M4’s inclusion of “a
demonstration, such as a study report” as an example of evidence that may be used to meet Requirement R4
and that this example of evidence is absent in MOD-008-1. This is an example of evidence in Measure M4 and
not required evidence to meet Requirement R4. Additionally, MOD-008-1 does have “study reports” as an
example of evidence that may be used to meet requirements in MOD-008-1. As a result of discussion, the SDT
added additional examples of evidence in Measure M4 that may, but are not required to, be used to meet
Requirement R4.
The language “… for a TOP that does not maintain TRM examples of evidence include, but are not limited to: an
affidavit, statement, or other document stating that the TOP does not maintain TRM …” was added to Measure
M4 to clarify what evidence is necessary if the TOP does not maintain TRM.

Requirement R5
There were many commenters who expressed concern regarding an error within Requirement R5, Parts 5.2.1
and 5.3.2. The SDT noted that this error has been fixed in the newly posted MOD-001-2.
There was a clarifying remark asking about the 30 calendar days to respond to a written request. To mirror with
the applicable FAC Reliability Standards, specifically FAC-011 and FAC-013, the SDT modified the 30 calendar
days to 45 calendar days.
There were several comments that the language “referencing this requirement” is unclear. The intent of the
language is for everyday routine communications to not be rolled into the reliability intent of the requirement.
The SDT made a clarifying change and added the word “specific” in front of requirement to demonstrate that a
requesting registered entity must reference the specific requirement when making a request. Based on industry
comments this word was added to specify that the request for information must reference Requirement R5 in
order to invoke Requirement R5, so that a request for information under the Reliability Standard could be
distinctly separate from a routine request for information.
There was a comment on FERC directive S-Ref 10206, Order 729 Paragraph 151, in which the directive notes that
those entities requesting the information with a reliability need shall demonstrate such need to the ERO. The
existing language in Requirement R5 is explicit. In lieu of forcing the ERO to determine who has a reliability need
for the information, the SDT decided to leave it to the entities to work out a solution.
Measure M5
There was a comment that there is no example of evidence for the TOP. The SDT reviewed the measure and
added examples of evidence to include the TOP.
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Consideration of Comments by Requirement

Confidentiality
One commenter stated that the “subject to confidentiality, regulatory, or security requirements” language may
be unclear. In response, the SDT added “the data owner’s” before the word “confidentiality”. The SDT noted
that this refinement will clarify whose confidentiality, regulatory, or security requirements are in place.

Requirement R6
One commenter stated that Requirement R6, Part 6.2 is not really a distinct requirement and the verbiage
should be included as a second sentence to Requirement R6, Part 6.1. Furthermore, the commenter stated that
Requirement 6, Part 6.1 does not need to be separate but should be included at the end of Requirement R6. In
summation, the commenter suggested that Requirement R6, Parts 6.1 and 6.2 be moved to the end of
Requirement R6. In response, the SDT reviewed and reformatted the requirement to incorporate both simple
data-request instances and requests for periodic data to be shared.
There was a clarifying remark asking about the 30 calendar days to respond to a written request. To mirror with
the applicable FAC Reliability Standards, specifically FAC-011 and FAC-013, the SDT modified the 30 calendar
days to 45 calendar days.
There were several comments that the language “referencing this requirement” is unclear. The intent of the
language is for everyday routine communications to not be rolled into the reliability intent of the requirement.
The SDT made a clarifying change and added the word “specific” in front of requirement to demonstrate that a
requesting registered entity must reference the specific requirement when making a request. Based on industry
comments this word was added to specify that the request for information must reference Requirement R6 in
order to invoke Requirement R6, so that a request for information under the Reliability Standard could be
distinctly separate from a routine request for information.
Confidentiality
One commenter stated that the “subject to confidentiality, regulatory, or security requirements” language may
be unclear. In response, the SDT added “the data owner’s” before the word “confidentiality”. The SDT noted
that this refinement will clarify whose confidentiality, regulatory, or security requirements are in place.

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MOD-001-2 Compliance Section Comments
There were several comments pertaining to the Compliance section of the proposed MOD-001-2 Reliability
Standard. Those comments are considered below by the appropriate sub-section.
Evidence Retention
One commenter requested rationale for the five year retention on methodology documents. In response, the
SDT noted that an outstanding directive from FERC Order No. 729 explains why five years is used. In paragraph
129 of that order, the Commission stated that, “If the Commission determines upon its own review of the data,
or upon review of a complaint, that it should investigate the implementation of the available transfer capability
methodologies, the Commission will need access to historical data. Accordingly, pursuant to section 215(d)(5) of
the FPA and section 39.5(f) of our regulations, the Commission directs the ERO to modify the Reliability
Standards so as to increase the document retention requirements to a term of five years, in order to be
consistent with the enforcement provisions established in Order No. 670.” Therefore, the SDT has retained the
five years for the implementation documents.
The SDT modified a bullet in this section that read, “Calculations and other components of implementation and
methodology documents shall be retained to show compliance in calculating…” to read “Components of the
calculations and the results of such calculations for all values contained in the implementation and methodology
documents.” This change was made to mirror the revised language in the requirements in which the data a
registered entity retains are the results of the calculations, not the calculations themselves. The SDT noted the
response also answers a related question concerning “values” to be retained.
Violation Severity Levels (VSLs)
Several commenters stated that the VSLs for Requirement R1 are unclear as to whether they refer to the
requirement elements that are set out in Requirement R1, Parts 1.1, 1.2, or 1.3 or all of them. In response, the
SDT noted that the VSLs are gradated based on how many requirement parts a registered entity’s TFC or TTC
methodology does not contain. In summary, the VSLs are not assigned to a specific requirement part, but for the
requirement as a whole.
One commenter suggested that the VSLs for Requirements R2 through R5 should be revised as there are only
severe VSLs. The SDT noted that the posted Requirements R2, R3, and R4 were binary requirements. From the
VSL Guidelines,3 binary requirement is a “pass or fail” type requirement where any degree of noncompliant
performance would result in totally or mostly missing the reliability intent of the requirement, then the single
VSL must be “Severe.” In the new posting of the revised Reliability Standard, Requirements R3 and R4 are the
only requirements that remain binary, as the new Requirement R2 has become more prescriptive and contain
requirement parts after the SDT reviewed and considered the comments.
A commenter noted that for the VSLs for Requirements R2, R3, and R4, that the phrase “prepare, keep current,
and implement” should not be in the VSLs and that the measured should not have subjective thresholds that
require three separate actions within a single requirement. In response, the SDT noted the phrase has been
removed from the requirements and will no longer be used within the VSLs.

3

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed

1. SAR and supporting package posted for comment on (July 11, 2013 – August 27, 2013).
2. Draft standard posted for first comment and ballot (July 11, 2013 – August 27, 2013).
3. Draft standard posted for additional comment and ballot (November 8, 2013 November 18, 2013).
Description of Current Draft

This draft standard is concluding informal development and will move to formal development
when authorized by the Standards Committee.

Anticipated Actions

Anticipated Date

Additional 45-day Formal Comment Period with Ballot

November 2013

Final Ballot

December 2013

Board of Trustees (Board) Adoption

December 2013

Filing to Applicable Regulatory Authorities

December 2013

Draft 2: October 4, 2013

Page 1 of 19

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Version History

Version

Date

1

August 26,
2008
November 5,
2009

1a
2

TBD

Action

Change Tracking

Adopted by the NERC Board
NERC Board Adopted Interpretation of
R2 and R8
Consolidation of MOD-001-1a, MOD004-1, MOD-008-1, MOD-028-1, MOD029-1a, and MOD-030-2

Interpretation
(Project 2009-15)

Definitions of Terms Used in the Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
When this standard receives ballot approval, the text boxes will be moved to the “Guidelines
and Technical Basis” section of the standard.
A. Introduction

1.

Title:

Available Transmission System Capability

2.

Number:

MOD-001-2

3.

Purpose:
To ensure that determinations of available transmission system transfer capability are
determined in a manner that supports the reliable operation of the Bulk-Power
System (BPS) and that the methodology and data underlying those determinations are
disclosed to those registered entities that need such information for reliability
purposes. This Reliability Standard ensures (1) that available transmission system
capability determinations account for system reliability limits, and (2) that planners
and operators of the BPS can request available transmission system capability
information from other Transmission Operators or Transmission Services Providers.

4.

Applicability:
4.1. Functional Entity
4.1.1 Transmission Operator
4.1.2 Transmission Service Provider
4.2. Exemptions: The following is exempt from MOD-001-2.
4.2.1 Functional Entities operating within the Electric Reliability Council of
Texas (ERCOT)

5.

Effective Date:
5.1. The standard shall become effective on the first day of the first calendar quarter
that is 18 months after the date that the standard is approved by an applicable
governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to
go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first
calendar quarter that is 18 months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
B. Requirements and Measures

Rationale for R1: Total Flowgate Capability (TFC) and Total Transfer Capability (TTC) are the starting points
for the Available Flowgate Capability (AFC) and Available Transfer Capability (ATC) values. AFC and ATC
values influence real-time conditions and have the ability to impact real-time operations. A Transmission
Operator (TOP) shall clearly document its methods of determining TFC and TTC so that any TOP or
Transmission Service Provider (TSP) that uses the information can clearly understand how the values are
determined. The TFC and TTC values shall account for any reliability constraints that limit those values as
well as system conditions forecasted for the time period for which those values are determined. The TFC
and TTC values shall also incorporate constraints on external systems when appropriate, in addition to
constraints on the TOP’s own system.

R1.

Each Transmission Operator that determines Total Flowgate Capability (TFC) or Total Transfer
Capability (TTC) shall develop a written methodology (or methodologies) for determining TFC or TTC
values. The methodology (or methodologies) shall reflect the Transmission Operator’s current
practices for determining TFC or TTC values. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
1.1 Each methodology shall describe the method used to account for the following limitations in
both the pre- and post-contingency state:
1.1.1

Facility ratings;

1.1.2

System voltage limits;

1.1.3

Transient stability limits;

1.1.4

Voltage stability limits; and

1.1.5

Other System Operating Limits (SOLs).

1.2 Each methodology shall describe the method used to account for each of the following
elements, provided such elements impact the determination of TFC or TTC:
1.2.1

The simulation of transfers performed through the adjustment of generation, Load, or
both;

1.2.2

Transmission topology, including, but not limited to, additions and retirements;

1.2.3

Expected transmission uses;

1.2.4

Planned outages;

1.2.5

Parallel path (loop flow) adjustments;

1.2.6

Load forecast; and

1.2.7

Generator dispatch, including, but not limited to, additions and retirements.

1.3 Each methodology shall describe the process for including any reliability-related constraints that
are requested to be included by another Transmission Operator, provided that (1) the request

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
references this specific requirement, and (2) the requesting Transmission Operator includes
those constraints in its TFC or TTC determination.
1.3.1 Each Transmission Operator that uses the Flowgate Methodology shall include in its
methodology an impact test process for including requested constraints. If a generator to
Load transfer in a registered entity’s area or a transfer to a neighboring registered entity
impact the requested constraint by five percent or greater, the requested constraint shall
be included in the TFC determination, otherwise the requested constraint is not required
to be included.
1.3.2 Each Transmission Operator that uses the Area Interchange or Rated System Path
Methodology shall describe the process it uses to account for requested constraints that
have a five percent or greater distribution factor for a transfer between areas in the TTC
determination; otherwise the requested constraint is not required to be included. When
testing transfers involving the requesting Transmission Operators area, the requested
constraint may be excluded.
1.3.3 A different method for determining whether requested constraints need to be included
in the TFC or TTC determination may be used if agreed to by the Transmission Operators.
M1. Each Transmission Operator that determines TFC or TTC shall provide its current methodology (or
methodologies) or other evidence (such as written documentation) to show that its methodology (or
methodologies) contains the following:
•

A description of the method used to account for the limits specified in part 1.1. Methods of
accounting for these limits may include, but are not limited to, one or more of the following:
o TFC or TTC being determined by one or more limits.
o Simulation being used to find the maximum TFC or TTC that remains within the limit.
o The application of a distribution factor in determining if a limit affects the TFC or TTC value.
o Monitoring a subset of limits and a statement that those limits are expected to produce the
most severe results.
o A statement that the monitoring of a select limit(s) results in the TFC or TTC not exceeding
another set of limits.
o A statement that one or more of those limits are not applicable to the TFC or TTC
determination.

•

A description of the method used to account for the elements specified in part 1.2, provided such
elements impact the determination of TFC or TTC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:
o A statement that the element is not accounted for since it does not affect the determination
of TFC or TTC.
o A description of how the element is used in the determination of TFC or TTC.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
•

(1.3) A copy of the request and a description of the method used to perform the impact test
(1.3.1) or account for the requested constraints (1.3.2).

•

The Transmission Operator shall also be using their current method to determine TFC or TTC.
Evidence of this could be, but is not limited to, a demonstration that a selection of currently
active TFC or TTC values were calculated based on the current methodology.

Rationale for R2: A TSP must clearly document its methods of determining AFC and ATC so that TOPs can
clearly understand how the values are determined. The AFC and ATC values shall account for system
conditions at the time those values would be used. Each TSP that uses the Flowgate Methodology shall
also use the AFC value determined by the TSP responsible for an external system constraint where
appropriate.

R2.

Each Transmission Service Provider that determines Available Flowgate Capability (AFC) or Available
Transfer Capability (ATC) shall develop an Available Transfer Capability Implementation Document
(ATCID) that describes the methodology (or methodologies) it uses to determine AFC or ATC values.
The methodology (or methodologies) shall reflect the Transmission Service Provider’s current
practices for determining AFC or ATC values. [Violation Risk Factor: Lower] [Time Horizon: Operations
Planning]
2.1. Each methodology shall describe the method used to account for the following elements that
impact the determination of AFC or ATC:
2.1.1.

The simulation of transfers performed through the adjustment of generation, Load, or
both;

2.1.2.

Transmission topology, including, but not limited to, additions and retirements;

2.1.3.

Expected transmission uses;

2.1.4.

Planned outages;

2.1.5.

Parallel path (loop flow) adjustments;

2.1.6.

Load forecast; and

2.1.7.

Generator dispatch, including, but not limited to, additions and retirements.

2.2. Each Transmission Service Provider that uses the Flowgate Methodology shall, for reliability
constraints identified in part 1.3, use the AFC determined by the Transmission Service Provider
for that constraint.
M2. Each Transmission Service Provider that determines AFC or ATC shall provide its current ATCID or
other evidence (such as written documentation) to show that its ATCID contains the following:
•

A description of the method used to account for the elements specified in part 2.1, provided such
elements impact the determination of AFC or ATC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:
o A description of how the element is used in the determination of AFC or ATC.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
o A statement that the element is not accounted for since it does not affect the determination
of AFC or ATC.
o A statement that the element is accounted for in the determination of TFC or TTC by the
Transmission Operator, and does not otherwise affect the determination of AFC or ATC.
•

Each Transmission Service Provider that uses the Flowgate Methodology shall provide a
description of the method in which AFC provided by another Transmission Service Provider was
used for the reliability constraints identified in part 1.3.

•

The Transmission Service Provider shall also be using their current method to determine AFC or
ATC. Evidence of this could be, but is not limited to, a demonstration that a selection of currently
active AFC or ATC values were calculated based on the current methodology.

Rationale for R3: Capacity Benefit Margin (CBM) is one of the values that may be used in determining the
AFC or ATC value. CBM is the amount of firm transmission transfer capability preserved by the transmission
provider for Load-Serving Entities (LSEs), who’s Loads are located on that TSPs system, to enable access by
the LSEs to generation from interconnected systems to meet resource reliability requirements. A clear
explanation of how the CBM value is developed is an important aspect of the TSPs ability to communicate
to TOPs how that AFC or ATC value was determined. Therefore anytime CBM is used (non-zero) a CBMID is
required to communicate the method of determining CBM.

R3. Each Transmission Service Provider that determines Capacity Benefit Margin (CBM) values shall
develop a Capacity Benefit Margin Implementation Document (CBMID) that describes its method for
establishing CBM. The method described in the CBMID shall reflect the Transmission Service
Provider’s current practices for determining CBM values. [Violation Risk Factor: Lower] [Time
Horizon: Operations Planning]
M3. Each Transmission Service Provider that determines CBM shall provide evidence, including, but not
limited to, its current CBMID, current CBM values, or other evidence (such as written
documentation, study reports, or supporting information) to demonstrate that it established CBM
values consistent with its methodology described in the CBMID. If a Transmission Service Provider
does not maintain CBM, examples of evidence include, but are not limited to, an affidavit,
statement, or other documentation that states the Transmission Service Provider does not maintain
CBM.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Rationale for R4: Transmission Reliability Margin (TRM) is one of the values that may be used in
determining the AFC or ATC value. TRM accounts for the inherent uncertainty in system conditions and the
need for operating flexibility to ensure reliable system operation as system conditions change. An
explanation by the TOP of how the TRM value is developed for use in the TSP’s determination of AFC and
ATC is an important aspect of the TSP’s ability to communicate to TOPs how that AFC or ATC value was
determined. Therefore, anytime a TOP provides a non-zero TRM to a TSP, a Transmission Reliability Margin
Implementation Document (TRMID) is required to communicate the method of determining TRM.

R4. Each Transmission Operator that determines Transmission Reliability Margin (TRM) values shall
develop a Transmission Reliability Margin Implementation Document (TRMID) that describes its
method for establishing TRM. The method described in the TRMID shall reflect the Transmission
Operator’s current practices for determining TRM values. [Violation Risk Factor: Lower][Time
Horizon: Operations Planning]
M4. Each Transmission Operator that determines TRM shall provide evidence including, but not limited
to, its current TRMID, current TRM values, or other evidence (such as written documentation,
study reports, or supporting information) to demonstrate that it established TRM values
consistent with its methodology described in the TRMID. If a Transmission Operator does not
maintain TRM, examples of evidence include, but are not limited to, an affidavit, statement, or
other documentation that states the Transmission Operator does not maintain TRM.
Rationale for R5: Clear communication of the methods of determining AFC, ATC, CBM, TFC, TRM, and TTC
are necessary to the reliable operation of the Bulk-Power System (BPS). A TOP and TSP are obligated to
make available their methodologies for determining AFC, ATC, CBM, TFC, TRM, and TTC to those with a
reliability need. The TOP and TSP are further obligated to respond to any requests for clarification on those
methodologies, provided that responding to such requests would not be contrary to the registered entities
confidentiality, regulatory, or security concerns. The purpose of this requirement is not to monitor every
communication that occurs regarding these values, but to ensure that those with reliability need have
access to the information. Therefore, the requirement is very specific on when it is invoked so that it does
not create an administrative burden on regular communications between registered entities.

R5. Within 45 calendar days of receiving a written request that references this specific requirement
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission
Planner, Transmission Service Provider, or any other registered entity that demonstrates a
reliability need, each Transmission Operator or Transmission Service Provider shall provide:
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
5.1.

A written response to any request for clarification of its TFC or TTC methodology, ATCID,
CBMID, or TRMID. If the request for clarification is contrary to the Transmission Operator’s
or Transmission Service Provider’s confidentiality, regulatory, or security requirements
then a written response shall be provided explaining the clarifications not provided, on

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
what basis and whether there are any options for resolving any of the confidentiality,
regulatory, or security concerns.
5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s
effective:
5.2.1 TRMID; and
5.2.2 TFC or TTC methodology.

5.3.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s
effective:
5.3.1 ATCID; and
5.3.2 CBMID.

M5. Examples of evidence include, but are not limited to:
• Dated records of the request and the Transmission Operator’s or Transmission Service
Provider’s response to the request;
• A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests; or
• A statement by the Transmission Operator or Transmission Service Provider that they do not
determine one or more of these values: AFC, ATC, CBM, TFC, TTC or TRM.
Rationale for R6: This requirement provides a mechanism for each TOP or TSP to access the best available
data for use in its calculation of AFC, ATC, CBM, TFC, TRM, and TTC values. Requirement R6 requires that a
TOP and TSP share their data, with the caveat that the TOP and TSP is not required to modify that data
from the form that they use or maintain it in. For data requests that involve providing data on a regular
interval, the TOP and TSP is not obligated to provide the data more frequently than either (1) once an hour,
or (2) as often as they update the data. The data provider is also not obligated to provide data that would
violate any of its confidentiality, regulatory, or security obligations. The purpose of this requirement is not
to monitor every data exchange that occurs regarding these values, but to ensure that those with reliability
need have access to the information. Therefore, the requirement is very specific on when it is invoked so
that it does not create an administrative burden on regular communications between registered entities.

R6. Each Transmission Operator or Transmission Service Provider that receives a written request from
another Transmission Operator or Transmission Service Provider for data related to AFC, ATC, TFC,
or TTC determinations that (1) references this specific requirement, and (2) specifies that the
requested data is for use in the requesting party’s AFC, ATC, TFC, or TTC determination shall take
one of the actions below. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
6.1. In responding to a written request for data on an ongoing basis, the Transmission Service
Provider or Transmission Operator shall make available its data on an ongoing basis no later
than 45 days from receipt of the written request. Unless otherwise agreed upon, the
Transmission Operator or Transmission Service Provider is not required to:

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
6.1.1 Alter the format in which it maintains or uses the data; or
6.1.2 Make available the requested data on a more frequent basis than it produces the
data and in no event shall it be required to provide the data more frequently than
once an hour.
6.2 In responding to all other data requests, each Transmission Operator or Transmission Service
Provider shall make available the requested data within 45 days of receipt of the written
request. Unless otherwise agreed upon, the Transmission Operator or Transmission Service
Provider is not required to alter the format in which it maintains or uses the data.
6.3 If making available any requested data under parts 6.1 or 6.2 of this requirement is contrary
to the Transmission Operator’s or Transmission Service Provider’s confidentiality, regulatory,
or security requirements, the Transmission Operator or Transmission Service Provider shall
not be required to make available that data; provided that, within 45 days of the written
request, it responds to the requesting registered entity specifying the data that is not being
provided, on what basis and whether there are any options for resolving any of the
confidentiality, regulatory or security concerns.
M6. Examples of evidence for a data request that involves providing data at regular intervals on an
ongoing basis (6.1), include, but are not limited to:
•

Dated records of a registered entity’s request, and examples of the response being met;

•

Dated records of a registered entity’s request, a statement from the requestor that the
request was met (demonstration that the response was met is not required if the requestor
confirms it is being provided); or

•

A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.

Examples of evidence for all other data requests (6.2) include, but are not limited to:
•

Dated records of a registered entity’s request, and the response to the request;

•

Dated records of a registered entity’s request, a statement from the requestor that the
request was met; or

•

A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.

An example of evidence of a response by the Transmission Operator or Transmission Service
Provider that providing the data would be contrary to the registered entity’s confidentiality,
regulatory, or security requirements (6.3) includes a response to the requestor specifying the data
that is not being provided, on what basis and whether there are any options for resolving any of
the confidentiality, regulatory, or security concerns.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
C. Compliance

1.

Compliance Monitoring Process:
1.1. Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” refers
to NERC or the Regional Entity in their respective roles of monitoring and enforcing
compliance with the NERC Reliability Standards.
1.2. Evidence Retention:
The following evidence retention periods identify the period of time a registered entity
is required to retain specific evidence to demonstrate compliance. For instances in
which the evidence retention period specified below is shorter than the time since the
last audit, the Compliance Enforcement Authority may ask the registered entity to
provide other evidence to show that it was compliant for the full time period since the
last audit.
•

Implementation and methodology documents shall be retained for five years.

•

Components of the calculations and the results of such calculations for all values
contained in the implementation and methodology documents.
o Hourly values for the most recent 14 days;
o Daily values for the most recent 30 days; and
o Monthly values for the most recent 60 days.

•

If a Transmission Operator or Transmission Service Provider is found non-compliant,
it shall keep information related to the non-compliance until mitigation is complete
and approved.

•

The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Assessment Processes:
•

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment
Processes” refers to the identification of the processes that will be used to evaluate
data or information for the purpose of assessing performance or outcomes with the
associated reliability standard.

1.4. Additional Compliance Information:
•

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None

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Table of Compliance Elements
R#

R1

Time
Horizon
Operations
Planning

VRF

Lower

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for one of the
limitations listed in
part 1.1 in its written
methodology. (1.1)

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for two of the
limitations listed in
part 1.1 in its written
methodology. (1.1)

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for any of the
limitations listed in
part 1.1 in its written
methodology. (1.1)

Each Transmission
Operator that
determines TFC or TTC
did not develop a
written methodology
for describing its
current practices for
determining TFC or
TTC values.

OR

OR

OR

OR

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for one of the element
listed in part 1.2 in its
written methodology,
provided that element
impacts its TFC or TTC
determination. (1.2)

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for two, three, or four
elements listed in part
1.2 in its written
methodology,
provided those
elements impacts its
TFC or TTC
determination. (1.2)

Each Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for five, six, or seven
elements of listed in
part 1.2 in its written
methodology,
provided those
elements impacts its
TFC or TTC
determination. (1.2)

Each Transmission
Operator that uses TFC
or TTC developed a
written methodology
for determining TFC or
TTC but the
methodology did not
reflect its current
practices for
determining TFC or
TTC values.

OR
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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

Each Transmission
Operator that
determines TFC or TTC
has not described the
process for including
any reliability-related
constraints that have
been requested by
another Transmission
Operator, provided the
constraints are also
used in the requesting
Transmission
Operator’s TFC or TTC
calculation and the
request referenced
part 1.3. (1.3)
OR
Each Transmission
Operator that
determines TFC or TTC
has not used (i) an
impact test process for
including requested
constraints, (ii) a
process to account for
requested constraints
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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R2

Operations
Planning

Lower

Moderate VSL

High VSL

that have a five
percent or greater
distribution factor for
a transfer between
areas in the TTC
determination, or (iii) a
mutually agreed upon
method for
determining whether
requested constraints
need to be included in
the TFC or TTC
determination. (1.3.1,
1.3.2, 1.3.3)
Each Transmission
Each Transmission
Each Transmission
Service Provider that
Service Provider that
Service Provider that
determines AFC or ATC determines AFC or ATC determines AFC or ATC
has not described its
has not described its
has not described its
method for accounting method for accounting method for accounting
for two, three, or four for five, six, or seven
for one of the
elements listed in part elements listed in part elements listed in part
2.1 in its written
2.1 in its written
2.1 in its written
methodology,
methodology,
methodology,
provided that element provided the elements provided the elements
impact its AFC or ATC
impacts its AFC or ATC impact its AFC or ATC
determination. (2.1)
determination. (2.1)
determination. (2.1)
OR

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Severe VSL

Each Transmission
Service Provider that
determines AFC or ATC
did not develop an
ATCID describing its
AFC or ATC
methodology.
OR
Each Transmission
Service Provider that
determines AFC or ATC
did not reflect its
current practices for
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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R3

Operations
Planning

Lower

None.

Moderate VSL

None.

High VSL
Each Transmission
Service Provider that
uses the Flowgate
Methodology did not
use the AFC
determined by the
Transmission Service
Provider for reliability
constraints identified
in part 1.3. (2.2)
None.

Severe VSL
determining AFC or
ATC values in its
ATCID.

Each Transmission
Service Provider that
uses CBM values did
not develop a CBMID
describing its method
for determining CBM
values.
OR
Each Transmission
Service Provider that
uses CBM values did
not reflect its current
practices for
determining CBM
values in its CBMID.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R4

Operations
Planning

Lower

None.

Moderate VSL
None.

High VSL
None.

Severe VSL
Each Transmission
Operator that uses
TRM values did not
develop a TRMID
describing its method
for determining TRM
values.
OR

R5

Operations
Planning

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Lower

Each Transmission
Operator that uses
TRM values did not
reflect its current
practices for
determining TRM
values in its TRMID.
Each Transmission
Each Transmission
Each Transmission
Each Transmission
Operator or
Operator or
Operator or
Operator or
Transmission Service
Transmission Service
Transmission Service
Transmission Service
Provider failed to
Provider did not
Provider did not
Provider did not
respond to a written
respond to a written
respond to a written
respond to a written
request by one or
request by one or
request by one or
request by one or
more of the registered more of the registered more of the registered more of the registered
entities specified in
entities specified in
entities specified in
entities specified in
Requirement R5 within Requirement R5 within Requirement R5 within Requirement R5.
45 calendar days from 76 calendar days from 106 calendar days
the date of the
from the date of the
the date of the
request, but did
request, but did
request, but did
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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R6

Operations
Planning

Draft 2: October 4, 2013

Lower

respond within 75
calendar days.
Each Transmission
Operator or
Transmission Service
Provider did not
respond to a written
request for data by
one or more of the
registered entities
specified in
Requirement R6 by
making the requested
data available within in
45 calendar days from
the date of the
request, but did
respond within 75
calendar days.

Moderate VSL
respond within 105
calendar days.
Each Transmission
Operator or
Transmission Service
Provider did not
respond to a written
request for data by
one or more of the
registered entities
specified in
Requirement R6 by
making data available
within 76 calendar
days from the date of
the request, but did
respond within 105
calendar days.

High VSL
respond within135
calendar days.
Each Transmission
Operator or
Transmission Service
Provider did not
respond to a written
request by one or
more of the registered
entities specified in
Requirement R6 by
making data available
within 106 calendar
days from the date of
the request, but did
respond within 135
calendar days.

Severe VSL

Each Transmission
Operator or
Transmission Service
Provider failed to
respond to a written
request for data by
making data available
to one or more of the
entities specified in
Requirement R6.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

D. Regional Variances

None.
E. Interpretations

None.
F. Associated Documents

None.

Draft 2: October 4, 2013

Page 18 of 19

Application Guidelines
Guidelines and Technical Basis
Please see the MOD A White Paper for further information regarding the technical basis for
each requirement.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.

Development Steps Completed

1. SAR and supporting package posted for comment on (July 11, 2013 – August 27, 2013).
2. Draft standard posted for first comment and ballot (July 11, 2013 – August 27, 2013).
3. Draft standard posted for additional comment and ballot (November 8, 2013 November 18, 2013).
Description of Current Draft

This draft standard is concluding informal development and will move to formal development
when authorized by the Standards Committee.

Anticipated Actions
SAR Authorized by the Standards Committee
Additional 45-day FormalDay Comment Period with BallotOpens

Anticipated Date
July
November 2013July

Nomination Period Opens

July

Standard Drafting Team Appointed

July

Initial Ballot is Conducted

August

Final Ballot is Conducted

December
2013September

Board of Trustees (Board) Adoption

December
2013November

Filing to Applicable Regulatory Authorities

December 2013

Draft 2: October 4July 3, 2013

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Effective Dates
1. MOD-001-2 shall become effective the first day of the seventh calendar quarter after
the effective date of the order providing applicable regulatory approval.
2. In those jurisdictions where no regulatory approval is required, MOD-001-2 shall
become effective the first day of the fifth calendar quarter after Board’s approval, or as
otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities.

Version History

Version

Date

1

August 26,
2008
November 5,
2009

1a
2

Draft 2: October 4July 3, 2013

TBD

Action

Change Tracking

Adopted by the NERC Board
NERC Board Adopted Interpretation of
R2 and R8
Consolidation of MOD-001-1a, MOD004-1, MOD-008-1, MOD-028-1, MOD029-1a, and MOD-030-2

Interpretation
(Project 2009-15)

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

Definitions of Terms Used in the Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or
revised definitions listed below become approved when the proposed standard is approved.
When the standard becomes effective, these defined terms will be removed from the individual
standard and added to the Glossary.
None.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
When this standard receives ballot approval, the text boxes will be moved to the “Guidelines
and Technical Basis” section of the standard.
A. Introduction

1.

Title:

Available Transmission System Capability

2.

Number:

MOD-001-2

3.

Purpose:
To ensure that determinations of available transmission system transfer capability are
determined in a manner that supports the reliable operation of the Bulk-Power
System (BPS) and that the methodology and data underlying those determinations are
disclosed to those registered entities that need such information for reliability
purposes. This Reliability Standard ensures (1) that available transmission system
capability determinations account for system reliability limits, and (2) that planners
and operators of the BPS can request available transmission system capability
information from other Transmission Operators or Transmission Services Providers.

3.

Purpose: (1) To ensure the reliable calculation of Total Flowgate Capability (TFC)
and Total Transfer Capability (TTC) values when those values are used by a
Transmission Service Provider to calculate Available Flowgate Capability (AFC) or
Available Transfer Capability (ATC) or used by a Reliability Coordinator; (2) to require
disclosure of how TFC, TTC, Capacity Benefit Margin (CBM), and Transmission
Reliability Margin (TRM) values are calculated for entities with a reliability need for
the information; and (3) to require the sharing of data with other entities with a
reliability need for the AFC, ATC, TFC, TTC, CBM, or TRM values.

4.

Applicability:
4.1. Functional Entity
4.1.1 Transmission Operator
4.1.2 Transmission Service Provider
4.2. Exemptions: The following is exempt from MOD-001-2.
4.2.1 Functional Entities operating within the Electric Reliability Council of
Texas (ERCOT)ERCOT

5.

Effective Date:
5.1. The standard shall become effective on the first day of the first calendar quarter
that is 18 months after the date that the standard is approved by an applicable
governmental authority or as otherwise provided for in a jurisdiction where
approval by an applicable governmental authority is required for a standard to
go into effect. Where approval by an applicable governmental authority is not
required, the standard shall become effective on the first day of the first
calendar quarter that is 18 months after the date the standard is adopted by the
NERC Board of Trustees or as otherwise provided for in that jurisdiction.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

Draft 2: October 4July 3, 2013

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
B. Requirements and Measures

Rationale for R1: Total Flowgate Capability (TFC) and Total Transfer Capability (TTC) are the starting points
for the Available Flowgate Capability (AFC) and Available Transfer Capability (ATC) values. AFC and ATC
values influence real-time conditions and have the ability to impact real-time operations. A Transmission
Operator (TOP) shall clearly document its methods of determining TFC and TTC so that any TOP or
Transmission Service Provider (TSP) that uses the information can clearly understand how the values are
determined. The TFC and TTC values shall account for any reliability constraints that limit those values as
well as system conditions forecasted for the time period for which those values are determined. The TFC
and TTC values shall also incorporate constraints on external systems when appropriate, in addition to
constraints on the TOP’s own system. Rationale for R1: TFC and TTC values are important to the reliability
of the bulk power system when they are used to determine AFC and ATC or in the real-time operation of
the transmission system. The Transmission Operator needs to calculate a value that protects reliability both
R1.

Each Transmission Operator that determines Total Flowgate Capability (TFC) or Total Transfer
Capability (TTC) shall develop a writtenprepare, keep current, and implement a TFC or TTC
methodology (or methodologies) for determiningcalculating its TFC or TTC values. The methodology
(or methodologies) shall reflect the Transmission Operator’s current practices for determining TFC or
TTC values., if: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]

1.1.

•

Each methodology Used by that Transmission Operator;

•

Requested by its Transmission Service Provider(s); or

•

Requested by its Reliability Coordinator.

The methodologies shall include:

1.1 A statement that the TTC or TFC shall describe the method used to account for the following
limitations in both the pre- and post-contingency state:
1.1.1

Facilityincorporate facility ratings;

1.1.2

System, voltage limits;

1.1.11.1.3
1.1.4
•

Transient, and stability limits pre- and post-contingency;

Voltage stability limits; and

Other A description of how this is accomplished;

1.1.5

What criteria (if any) is used to select which of the limits, or System Operating Limits
(SOLs).

•

Each methodology shall describe the method used), are relevant to account for each of the
calculation; and

•

The rationale for the selection of the TTC or TFC method being used.

1.2 The methodologies shall address, at a minimum, the following elements, provided such
elements impact of the determination of TFC or TTC calculation:

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
1.2.1

TheHow simulation of transfers are performed through the adjustment of generation,
Load, or both;

1.2.2

Transmission topology, including, but not limited to, additions and retirements;

1.2.3

ExpectedCurrently approved and projected transmission uses;

1.2.4

Planned outages;

1.2.5

Parallel path (loop flow) adjustments;

1.2.6

Load forecast; and

1.2.7

Generator dispatch, including, but not limited to, additions and retirements.

1.3 Each methodology shall describe the process for includingThe methodologies shall include any
reliability-related constraints that are requested to be included by another Transmission
Operator, provided that (1) the request references this specific requirement, and (2) the
requesting Transmission Operator includes those constraints are also used in itsthat
Transmission Operator’s TFC or TTC determinationcalculation.
1.3.1 Each Transmission Operator that uses the Flowgate Methodology shall include in its
methodology an impact test process for including requested constraints. If a generator to
Load transfer in a registered entity’s area or a transfer to a neighboring registered entity
impact the requested constraint by five percent or greater, the requested constraint shall
be included in the TFC determination, otherwise the requested constraint is not required
to be included.
1.3.2 Each Transmission Operator that uses the Area Interchange or Rated System Path
Methodology shall describe the process it uses to account for requested constraints that
have a five percent or greater distribution factor for a transfer between areas in the TTC
determination; otherwise the requested constraint is not required to be included. When
testing transfers involving the requesting Transmission Operators area, the requested
constraint may be excluded.
1.3.3 A different method for determining whether requested constraints need to be included
in the TFC or TTC determination may be used if agreed to by the Transmission Operators.
1.3.1 Each Transmission Operator that determines TFC or TTC shall provide its current
methodology (or methodologies) or other The Transmission Operator shall use a
distribution factor (Power Transfer Distribution Factor (PTDF) or Outage Transfer
Distribution Factor (OTDF)) of five percent or less when determining if these constraints
should be monitored.
1.2.

The methodologies shall address the periodicity for the Transmission Operator to provide
updated TFC or TTC values to the Transmission Service Provider.

M1. Examples of evidence (such as written documentation) to show that its methodology (or
methodologies) contains the following:
•

A description of the method used to account for the limits specified in part 1.1. Methods of
accounting for these limits may include, but are not limited to, one or more of the following:

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Page 7 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
o TFC or TTC being determined by one or more limits.
o Simulation being used to find the maximum TFC or TTC that remains within the limit.
o The application of a distribution factor in determining if a limit affects the TFC or TTC value.
•

Monitoring a subsetA dated effective methodology that is posted on the Transmission
Operator's website, or their Transmission Service Provider’s website, or on the Open Access
Same-Time Information System (OASIS);

•

Descriptions within the methodology regarding how constraints identified by another
Transmission Operator are included and how a distribution factor is applied, or a statement
that such a request has not been made, or the TTC or TFC calculation does not use PTDF or
OTDF in the calculation; or

•

Language in the TFC or TTC methodology that specifies the periodicity of providing updated
TFC or TTC values to the Transmission Service Provider and evidence that the updated values
were provided according to the specified timeframes.

o If the Transmission Operator and Transmission Service Provider are the same entity then
evidence of limits and providing the values can be established by a statement that those
Rationale for R2:
ATC is a prediction of the remaining amount of power that can be transferred on a path between two
systems for defined system conditions. AFC is a prediction of the amount of additional power for defined
system conditions that could flow over a particular flowgate, which may involve one or more paths
between systems. The ATC or AFC value influences, to varying degrees depending on the locality, the
system conditions that the operator inherits in real time, which gives the Transmission Operator and
others an interest in understanding how the values are calculated. To ensure that the Transmission
Operator and others have this information, the Transmission Service Provider must have an Available
Transfer Capability Implementation Document (ATCID) that accurately describes the current process of
determining this value.
limits are expected to produce the most severe results.
o A statement that the monitoring of a select limit(s) results in the TFC or TTC not exceeding
another set of limits.
o A statement that one or more of those limits are not applicable to the TFC or TTC
determination.
•

A description of the method used to account for the elements specified in part 1.2, provided such
elements impact the determination of TFC or TTC. Methods of accounting for these elements
may include, butthey are not limited to, one or more of the following:
o A statement that the element is not accounted for since it does not affect the determination
of TFC or TTC.
o A description of how the element is used in the determination of TFC or TTC.same entity.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
•

(1.3) A copy of the request and a description of the method used to perform the impact test
(1.3.1) or account for the requested constraints (1.3.2).

•

The Transmission Operator shall also be using their current method to determine TFC or TTC.
Evidence of this could be, but is not limited to, a demonstration that a selection of currently
active TFC or TTC values were calculated based on the current methodology.

Rationale for R2: A TSP must clearly document its methods of determining AFC and ATC so that TOPs can
clearly understand how the values are determined. The AFC and ATC values shall account for system
conditions at the time those values would be used. Each TSP that uses the Flowgate Methodology shall
also use the AFC value determined by the TSP responsible for an external system constraint where
appropriate.

R2.

Each Transmission Service Provider that determines Available Flowgate Capability (AFC) or
Available Transfer Capability (ATC) shall developshall prepare, keep current, and implement an
Available Transfer Capability Implementation Document (ATCID) that describes the methodology (or
methodologies) it uses to determine AFC or ATC values. The methodology (or methodologies) shall
reflect the Transmission Service Provider’s current practices for determining AFC or ATCused to
calculate ATC or AFC values. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
2.1. Each methodology shall describe the method used to account for the following elements that
impact the determinationExamples of AFC or ATC:
2.1.1.

The simulation of transfers performed through the adjustment of generation, Load, or
both;

2.1.2.

Transmission topology, including, but not limited to, additions and retirements;

2.1.3.

Expected transmission uses;

2.1.4.

Planned outages;

2.1.5.

Parallel path (loop flow) adjustments;

2.1.6.

Load forecast; and

2.1.7.

Generator dispatch, including, but not limited to, additions and retirements.

2.2. Each Transmission Service Provider that uses the Flowgate Methodology shall, for reliability
constraints identified in part 1.3, use the AFC determined by the Transmission Service Provider
for that constraint.
M2. Each Transmission Service Provider that determines AFC or ATC shall provide its current ATCID or
other evidence (such as written documentation) to show that its ATCID contains the following:
•

A description of the method used to account for the elements specified in part 2.1, provided such
elements impact the determination of AFC or ATC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:

Draft 2: October 4, 2013

Page 9 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
o A description of how the element a dated effective ATCID that is used in the determination of
AFC or ATC.
o A statement that the element is not accounted for since it does not affect the determination
of AFC or ATC.
o A statement that the element is accounted for in the determination of TFC or TTC byposted
on the Transmission Operator, and does not otherwise affect the determination of AFC or
ATC.
•

Each Transmission Service Provider that uses the Flowgate Methodology shall provide a
description of the method in which AFC provided by another Transmission Service Provider was
used for the reliability constraints identified in part 1.3.

•

The Transmission Service Provider shall also be using their current method to determine AFC or
ATC. Evidence of this could be, but is not limited to, Provider’s website or OASIS and a
demonstration that a selection ofselect currently active AFC or ATC values of ATC were calculated
based on the current methodology. ATCID.

Rationale for R3:
Capacity Benefit Margin (CBM) is one of the values that may be a value used in by a Transmission Service
Provider when determining ATC. To ensure transparency and reliability, the Transmission Service Provider
must have a Capacity Benefit Margin Implementation Document (CBMID) that accurately describes the AFC
or ATC value. CBM is current process of determining this value that can be shared with other entities with a
reliability need to understand the amount of firm transmission transfer capability preserved by the
transmission providerTransmission Service Provider’s process for Load-Serving Entities (LSEs), who’s Loads
are located on that TSPs system, to enable access bycreating the CBM value. When a Transmission Service
Provider does not use CBM, the LSEs to generation from interconnected systems to meet resource
reliability requirements. A clear explanation of how value in the ATC calculation is zero.
The CBM value is developed is an important aspect ofcould have been included in the TSPs ability to
communicate to TOPs howATCID. However, Transmission Service Providers have other obligations (tariffs, contracts, future
NAESB standards) that AFC or ATC value was determined. Therefore anytime CBM is used (non-zero) a CBMID
is required to communicatereference the method of determining CBMCBMID; keeping it as its own document
seemed to be less burdensome then requiring its inclusion in the ATCID.

R3. Each Transmission Service Provider that determines Capacity Benefit Margin (CBM) values shall
developprepare, keep current, and implement a Capacity Benefit Margin Implementation Document
(CBMID) that describes its method for establishing CBM. The method described in the CBMID shall
reflect the Transmission Service Provider’s current practices for determining CBM values. [Violation
Risk Factor: Lower] [Time Horizon: Operations Planning]margins to protect system reliability during a
declared NERC Energy Emergency Alert 2 or higher.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
M3. Each Transmission Service ProviderProviders that determines do not use Capacity Benefit Margin
(CBM) shall provide evidence, including, but not limited to, its current CBMID, current CBM values,
or other evidence (such as written documentation, study reports, or supporting information) to
demonstrate that it established CBM values consistent with its methodology describedstate this in
the CBMID. If a Transmission Service Provider does not maintain CBM, examples of evidence
include, but are not limited to, an affidavit, statement, or other documentationa dated effective
CBMID that is posted on the Transmission Service Provider’s website or OASIS and a demonstration,
such as a study report, that statesselect currently active values of CBM were determined per the
CBMID, if the Transmission Service Provider does not maintainProviders uses CBM.

Rationale for R4:
Transmission Reliability Margin (TRM) is one of the values that may be used in additional capacity held by a
Transmission Service Provider when determining the AFC or ATC value. TRM accounts for the inherent
uncertainty in system conditions and the need forproviding additional operating flexibilitymargin to a
Transmission Operator. To ensure reliable system operation as system conditions change. An explanation
by the TOP of how the TRM value is developed for use in the TSP’s determination of AFCtransparency and
ATC is an important aspect of the TSP’s ability to communicate to TOPs how that AFC or ATC value was
determined. Therefore, anytime a TOP provides a non-zero TRM to a TSP,reliability, the Transmission
Operator must have a Transmission Reliability Margin Implementation Document (TRMID) is required to
communicate the methodthat accurately describes their current process of determining TRM.this value
and can be shared with entities that have a reliability need to understand the Transmission Operator’s
process for creating the TRM value. When a Transmission Service Provider does not utilize TRM, the value

R4. Each Transmission Operator that determines Transmission Reliability Margin (TRM) values shall
developprepare, keep current, and implement a Transmission Reliability Margin Implementation
Document (TRMID) that describes its method for establishing TRM. The method described in the
TRMID shall reflect the Transmission Operator’s current practices for determining TRM values.
[Violation Risk Factor: Lower][Time Horizon: Operations Planning]margins to protect system
reliability.
M4. Each Transmission OperatorOperators that determines TRM shall provide evidence including,
butdo not limited to, its current TRMID, current TRM values, or other evidence (such as written
documentation, study reports, or supporting information) to demonstrate that it established TRM
values consistent with its methodology described use Transmission Reliability Margin (TRM) shall
state this in the TRMID. If a Transmission Operator does not maintain TRM, examples of evidence
include, but are not limited to, an affidavit, statement, or other documentation that statesa dated
effective TRMID that is posted on the Transmission Operator does not maintain TRM.Operator’s
website or OASIS and a demonstration, such as a study report, that select currently active values
of TRM were determined per the TRMID, if the Transmission Operator uses TRM.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
Rationale for R5: Clear communication of the methods of determining AFC, ATC, CBM, TFC, TRM, and TTC
are necessary to the reliable operation of the Bulk-Power System (BPS). A TOP and TSP are obligated to
make available their methodologies for determining AFC, ATC, CBM, TFC, TRM, and TTC to those with a
reliability need. The TOP and TSP are further obligated to respond to any requests for clarification on those
methodologies, provided that responding to such requests would not be contrary to the registered entities
confidentiality, regulatory, or security concerns. The purpose of this requirement is not to monitor every
communication that occurs regarding these values, but to ensure that those with reliability need have
access to the information. Therefore, the requirement is very specific on when it is invoked so that it does
not create an administrative burden on regular communications between registered entities.

R5. Within 4530 calendar days of receiving a written request that references this specific requirement
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission
Planner, Transmission Service Provider, or any other registered entity that demonstrates a
reliability need, each Transmission Operator or Transmission Service Provider and Transmission
Operator (subject to confidentiality, regulatory, or security requirements) shall provide: [Violation
Risk Factor: Lower] [Time Horizon: Operations Planning]
5.1.

A written response to any request for clarification of its TFCATC or TTCAFC methodology,
ATCID, CBMID, or TRMID. If the request for clarification is contrary to the Transmission
Operator’s or Transmission Service Provider’s confidentiality, regulatory, or security
requirements then a written response shall be provided explaining the clarifications not
provided, on what basis and whether there are any options for resolving any of the
confidentiality, regulatory, or security concerns.

5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s
effective:
5.2.1 TRMIDCBMID; and
5.2.2 TFC or TTC methodology.

5.3.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s
effective:
5.3.1 ATCID; and
5.3.2 TRMIDCBMID.

M5. Examples of evidence include, but are not limited to, dated records of the request from a Planning
Coordinator, Reliability Coordinator, Transmission Operator, Transmission Planner, Transmission
Service Provider, or another registered entity who demonstrates a reliability need; the
Transmission Service Provider’s response to the request; and a statement by the Transmission
Service Provider that they have received no requests.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

Rationale for R6: This requirement provides a mechanism for each TOP or TSP to access the best available data
for use in its calculation of AFC, ATC, CBM, TFC, TRM, and TTC values. Requirement R6 requires that a TOP and
TSP share their data, with the caveat that the TOP and TSP is not required to modify that data from the form
that they use or maintain it in. For data requests that involve providing data on a regular interval, the TOP and
TSP is not obligated to provide the data more frequently than either (1) once an hour, or (2) as often as they
update the data. The data provider is also not obligated to provide data that would violate any of its
confidentiality, regulatory, or security obligations. The purpose of this requirement is not to monitor every data
exchange that occurs regarding these values, but to ensure that those with reliability need have access to the
information. Therefore, the requirement is very specific on when it is invoked so that it does not create an
administrative burden on regular communications between registered entities.
R6. Each Transmission Operator or Transmission Service Provider that receives a written request from
another Transmission Operator or Transmission Service Provider for data related to AFC, ATC, TFC,
or TTC determinations that (1) references under this specific requirement, and (2) specifies that
the requested data is for use in the requesting party’s AFC, ATC, TFC, or TTC determination shall
take one of the actions below. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning].
•

Dated records of the registered entity’s request;

•

at intervals; or

•

A statement from the requestor that the request is being met.

6.1. In responding tothe case of a writtendata request forthat involves the providing of data on
an ongoing basis,regular intervals, examples of evidence include, but are not limited
to:Examples of the Transmission Service Provider or Transmission Operator shall make
available its data on an ongoing basis no later than 45 days from receipt of the written
request. Unless otherwise agreed upon, the Transmission Operator or Transmission Service
Provider is not required to:
6.1.1 Alter the format in which it maintains or uses the data; or
6.1.2 Make available the requested data on a more frequent basis than it produces the
data and in no event shall it be required to provide the data more frequently than
once an hour.
6.2 In responding to all other data requests, each Transmission Operator or Transmission Service
Provider shall make available the requested data within 45 days of receipt of the written
request. Unless otherwise agreed upon, the Transmission Operator or Transmission Service
Provider is not required to alter the format in which it maintains or uses the data.
6.3 If making available any requested data under parts 6.1 or 6.2 of this requirement is contrary
to the Transmission Operator’s or Transmission Service Provider’s confidentiality, regulatory,
or security requirements, the Transmission Operator or Transmission Service Provider shall
not be required to make available that data; provided that, within 45 days of the written
request, it responds to the requesting registered entity specifying the data that is not being

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
provided, on what basis and whether there are any options for resolving any of the
confidentiality, regulatory or security concerns.
M6. Examples of evidence for a data request that involves providing data at regular intervals on an
ongoing basis (6.1), include, but are not limited to:
•

Dated records of a registered entity’s request, and examples of the response being met;

•

Dated records of a registered entity’s request, a statement from the requestor that the
request was met (demonstration that the response was met is not required if the requestor
confirms it is being provided); or

•

A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.

Examples of evidence for all other data requests (6.2) include, but are not limited to:
•

Dated records of a registered entity’s request, and the response to the request;

•

Dated records of a registered entity’s request, a statement from the requestor that the
request was met; or

•

A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.

An example of evidence of a response by the Transmission Operator or Transmission Service
Provider that providing the data would be contrary to the registered entity’s confidentiality,
regulatory, or security requirements (6.3) includes a response to the requestor specifying the data
that is not being provided, on what basis and whether there are any options for resolving any of
the confidentiality, regulatory, or security concerns.

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MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
C. Compliance

1.

Compliance Monitoring Process:
1.1. Compliance Enforcement Authority:
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority”
refers to NERC or the Regional Entity in their respective roles of monitoring and
enforcing compliance with the NERC Reliability Standards.
1.2. Evidence Retention:
The following evidence retention periods identify the period of time a registeredan
entity is required to retain specific evidence to demonstrate compliance. For
instances in which the evidence retention period specified below is shorter than the
time since the last audit, the Compliance Enforcement Authority may ask the
registered entity to provide other evidence to show that it was compliant for the full
time period since the last audit.
•

Implementation and methodology documents shall be retained for five years.

•

Components of the calculationsCalculations and the results of such calculations
for all values contained in theother components of implementation and
methodology documents. shall be retained to show compliance in calculating:
o Hourly values for the most recent 14 days;
o Daily values for the most recent 30 days; and
o Monthly values for the most recent 60 days.

•

If a Transmission Operator or Transmission Service Provider responsible entity is
found non-compliant, it shall keep information related to the non-compliance
until mitigation is complete and approved.

•

The Compliance Enforcement Authority shall keep the last audit records and all
requested and submitted subsequent audit records.

1.3. Compliance Monitoring and Assessment Processes:
•

As defined in the NERC Rules of Procedure, “Compliance Monitoring and
Assessment Processes” refers to the identification of the processes that will be
used to evaluate data or information for the purpose of assessing performance
or outcomes with the associated reliability standard.

1.4. Additional Compliance Information:
•

Draft 2: October 4, 2013

None

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability
•
D. Regional Variances

None.
E. Interpretations

None.
F. Associated Documents

None.
Table of Compliance Elements
R#

R1

Time
Horizon
Operations
Planning

VRF

Lower

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

EachThe Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for one of the
limitations listed in
part 1.1 in its
writtenprepared, kept

EachThe Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for two of the
limitations listed in
part 1.1 in its
writtenprepared, kept

EachThe Transmission
Operator that
determines TFC or TTC
has not described its
method for accounting
for any of the
limitations listed in
part 1.1 in its written

EachThe Transmission
Operator that
determines TFC or TTC
did not developprepare,

current, and implemented a

current, and implemented a

prepared, kept current, and
implemented a

methodology. (1.1)

methodology. (1.1)

methodology. (1.1)

OR

OR

Each that is used by its
Transmission Operator
that determines TFC or

Each that is used by its
Transmission Operator
that determines TFC or

keep current, or implement

a written methodology
for describing its
current practices for
determining TFC or TTC
values.
OR

OR
Each that is used by its
Transmission Operator
that determines TFC or
Draft 2: October 4, 2013

Each Transmission
Operator that uses TFC
or TTC developed a
written methodology
Page 16 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

Draft 2: October 4, 2013

VRF

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

TTC has not described
its method for
accounting for one of
the element listed in
part 1.2 in its written
methodology, provided
that element impacts
its TFC or TTC
determination. (1.2)

TTC has not described
its method for
accounting for two,
three, or four elements
listed in part 1.2 in its
written methodology,
provided those
elements impacts its
TFC or TTC
determination.
(1.2)Service Provider, but

TTC has not described
its method for
accounting for five, six,
or seven elements of
listed in part 1.2 in its
written methodology,
provided those
elements impacts its
TFC or TTC
determination. (1.2)

for determining TFC or
TTC but the
methodology did not
reflect its current
practices for
determining TFC or TTC
values.

Service Provider, but does
not address one of the
requirement parts.

does not address two of the
requirement parts.

OR

.

Each Transmission
Operator that
determines TFC or TTC
has not described the
process for including
any reliability-related
constraints that have
been requested by
another Transmission
Operator, provided the
constraints are also
used in the requesting
Transmission
Operator’s TFC or TTC
calculation and the
request referenced
Page 17 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

part 1.3. (1.3)
OR
Each Transmission
Operator that
determines TFC or TTC
has not used (i) an
impact test process for
including requested
constraints, (ii) a
process to account for
requested constraints
that have a five
percent or greater
distribution factor for a
transfer between areas
in the TTC
determination, or (iii) a
mutually agreed upon
method for
determining whether
requested constraints
need to be included in
the TFC or TTC
determination. (1.3.1,
1.3.2, 1.3.3)Service
Provider, but does not
address three of the
Draft 2: October 4, 2013

Page 18 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

requirement parts.

R2

Operations
Planning

Lower

Each Transmission
Service Provider that
determines AFC or ATC
has not described its
method for accounting
for one of the elements
listed in part 2.1 in its
written methodology,
provided that element
impacts its AFC or ATC
determination. (2.1)

Each Transmission
Service Provider that
determines AFC or ATC
has not described its
method for accounting
for two, three, or four
elements listed in part
2.1 in its written
methodology, provided
the elements impact its
AFC or ATC
determination. (2.1)

None.

None.

Each Transmission
Service Provider that
determines AFC or ATC
has not described its
method for accounting
for five, six, or seven
elements listed in part
2.1 in its written
methodology, provided
the elements impact its
AFC or ATC
determination. (2.1)
OR
Each Transmission
Service Provider that
uses the Flowgate
Methodology did not
use the AFC
determined by the
Transmission Service
Provider for reliability
constraints identified

Draft 2: October 4, 2013

EachThe Transmission
Service Provider that
determines AFC or ATC
didhas not
developprepared an
ATCID describing its
AFC or ATC
methodology.
OR
Each
The Transmission
Service Provider that
determines AFC or ATC
didhas not reflect
itskept current practices
for determining AFC or
ATC values in itsan
ATCID.
OR
The Transmission Service
Provider has not
implemented an ATCID.
Page 19 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R3

Operations
Planning

Lower

None.

Moderate VSL
None.

High VSL
in part 1.3. (2.2)None.
None.

Severe VSL
EachThe Transmission
Service Provider that
uses CBM values didhas
not developprepared a
CBMID describing its
method for
determining CBM
values.
OR
EachThe Transmission
Service Provider that
uses CBM values didhas
not reflect itskept
current practices for
determining CBM
values in itsa CBMID.
OR
The Transmission Service
Provider has not
implemented a CBMID.

Draft 2: October 4, 2013

Page 20 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

VRF

Violation Severity Levels (VSLs)
Lower VSL

R4

Operations
Planning

Lower

None.

Moderate VSL
None.

High VSL
None.

Severe VSL
EachThe Transmission
Operator that uses
TRM values didhas not
developprepared a
TRMID describing its
method for
determining TRM
values.
OR
EachThe Transmission
Operator that uses
TRM values didhas not
reflect itskept current
practices for
determining TRM
values in itsa TRMID.
OR
The Transmission Operator
has not implemented a

R5

Operations
Planning

Draft 2: October 4, 2013

Lower

Each Transmission
Operator or
Transmission Service
Provider did not
respondThe responsible
entity responds to a

Each Transmission
Operator or
Transmission Service
Provider did not
respondThe responsible
entity responds to a

Each Transmission
Operator or
Transmission Service
Provider did not
respondThe responsible
entity responds to a

TRMID.
Each Transmission
Operator or
Transmission Service
Provider failedThe
responsible entity fails to
respond to a written
Page 21 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

R6

Time
Horizon

Operations
Planning

Draft 2: October 4, 2013

VRF

Lower

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

Severe VSL

written request by one
or more of the
registered entities
specified in
Requirementrequirement
R5 within 45 in 31 or
more calendar days
from the date of the
request, but did
respond within 75not
more than 60 calendar
days after the request.
Each Transmission
Operator or
Transmission Service
Provider did not
respondThe responsible
entity responds to a
written request for
data by one or more of
the registered entities
specified in
Requirementrequirement
R6 by making the
requestedto share data
available withinused in
45their TTC or ATC

written request by one
or more of the
registered entities
specified in
Requirementrequirement
R5 within 76 in 61 or
more calendar days
from the date of the
request, but did
respond within 105not
more than 90 calendar
days after the request.
Each Transmission
Operator or
Transmission Service
Provider did not
respondThe responsible
entity responds to a
written request for
data by one or more of
the registered entities
specified in
Requirementrequirement
R6 by making data
available within 76to

written request by one
or more of the
registered entities
specified in
Requirementrequirement
R5 within 106 in 91 or
more calendar days
from the date of the
request, but did
respond within135not
more than 120 calendar
days after the request.
Each Transmission
Operator or
Transmission Service
Provider did not
respondThe responsible
entity responds to a
written request by one
or more of the
registered entities
specified in
Requirementrequirement
R6 by makingto share
data available within
106used in their TTC or

request by one or
more of the entities
specified in
Requirementrequirement
R5.

calculation in 31 or more

share data used in their TTC
or ATC calculation in 61 or
more calendar days

calendar days from the

from the date of the

Each Transmission
Operator or
Transmission Service
Provider failedThe
responsible entity fails to
respond to a written
request for data by
making data available
toby one or more of the
entities specified in
Requirementrequirement
R6.

ATC calculation in 91 or
more calendar days

from the date of the
Page 22 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

R#

Time
Horizon

Draft 2: October 4, 2013

VRF

Violation Severity Levels (VSLs)
Lower VSL

Moderate VSL

High VSL

date of the request,
but did respond within
75not more than 60
calendar days after the
request.

request, but did
respond within 105not
more than 90 calendar
days after the request.

request, but did
respond within 135not
more than 120 calendar
days after the request.

Severe VSL

Page 23 of 25

MOD-001-2 — Modeling, Data, and Analysis — Available Transmission System Capability

D. Regional Variances

None.
E. Interpretations

None.
F. Associated Documents

None.

October 4, 2013

Page 24 of 25

Application Guidelines
Guidelines and Technical Basis
Please see the MOD A White Paper for further information regarding the technical basis for
each requirement.

Draft 2: October 4July 3, 2013

Page 25 of 25

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will 
be removed when the standard becomes effective.  
Note: On October 15, 2013, the redline to the last posting document was revised to correct 
formatting errors within the Rationale boxes that affected R1, M1, and M5, and clarify some of the 
redlining.  
No changes were made to the clean version of posted MOD‐001‐2. The original version of the 
redline document will remain posted on the project page. 

Development Steps Completed

1. SAR and supporting package posted for comment on (July 11, 2013 – August 27, 2013).  
2. Draft standard posted for first comment and ballot (July 11, 2013 – August 27, 2013). 
3. Draft standard posted for additional comment and ballot (November 8, 2013 ‐ 
November 18, 2013). 
Description of Current Draft

This draft standard is concluding informal development and will move to formal development 
when authorized by the Standards Committee. 

Anticipated Actions 
SAR Authorized by the Standards Committee 
Additional 45‐day FormalDay Comment Period with BallotOpens 

Anticipated Date 
July 
November 2013July 

Nomination Period Opens 

July 

Standard Drafting Team Appointed 

July  

Initial Ballot is Conducted 

August 

Final Ballot is Conducted 

December 
2013September 

Board of Trustees (Board) Adoption 

December 
2013November  

Filing to Applicable Regulatory Authorities 

December 2013 

Draft 2: October 4July 3, 2013   

Page 1 of 26 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
Effective Dates
1. MOD‐001‐2 shall become effective the first day of the seventh calendar quarter after 
the effective date of the order providing applicable regulatory approval.  
2. In those jurisdictions where no regulatory approval is required, MOD‐001‐2 shall 
become effective the first day of the fifth calendar quarter after Board’s approval, or as 
otherwise made effective pursuant to the laws applicable to such ERO governmental 
authorities. 

Version History

Version 

Date 

1 

August 26, 
2008 
November 5, 
2009 

1a 
2 

TBD 

Draft 2: October 4July 3, 2013   

Action 

Change Tracking 

Adopted by the NERC Board  

NERC Board Adopted Interpretation of 
R2 and R8 
Consolidation of MOD‐001‐1a, MOD‐
004‐1, MOD‐008‐1, MOD‐028‐1, MOD‐
029‐1a, and MOD‐030‐2 

Interpretation 
(Project 2009‐15) 

Page 2 of 26 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
Definitions of Terms Used in the Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms 
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or 
revised definitions listed below become approved when the proposed standard is approved. 
When the standard becomes effective, these defined terms will be removed from the individual 
standard and added to the Glossary. 
None.

Draft 2: October 4July 3, 2013   

Page 3 of 26 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
When this standard receives ballot approval, the text boxes will be moved to the “Guidelines 
and Technical Basis” section of the standard. 
A. Introduction

1.

Title: 

Available Transmission System Capability 

2.

Number: 

MOD‐001‐2 

3.

Purpose: 

To ensure that determinations of available transmission system transfer capability are 
determined in a manner that supports the reliable operation of the Bulk‐Power 
System (BPS) and that the methodology and data underlying those determinations are 
disclosed to those registered entities that need such information for reliability 
purposes. This Reliability Standard ensures (1) that available transmission system 
capability determinations account for system reliability limits, and (2) that planners 
and operators of the BPS can request available transmission system capability 
information from other Transmission Operators or Transmission Services Providers.  
3.

Purpose:  (1) To ensure the reliable calculation of Total Flowgate Capability (TFC) 
and Total Transfer Capability (TTC) values when those values are used by a 
Transmission Service Provider to calculate Available Flowgate Capability (AFC) or 
Available Transfer Capability (ATC) or used by a Reliability Coordinator; (2) to require 
disclosure of how TFC, TTC, Capacity Benefit Margin (CBM), and Transmission 
Reliability Margin (TRM) values are calculated for entities with a reliability need for 
the information; and (3) to require the sharing of data with other entities with a 
reliability need for the AFC, ATC, TFC, TTC, CBM, or TRM values. 

4.

Applicability: 
4.1. Functional Entity  
4.1.1 Transmission Operator 
4.1.2 Transmission Service Provider  
4.2. Exemptions: The following is exempt from MOD‐001‐2. 
4.2.1 Functional Entities operating within the Electric Reliability Council of 
Texas (ERCOT)ERCOT  

5.

Effective Date:  
5.1. The standard shall become effective on the first day of the first calendar quarter 
that is 18 months after the date that the standard is approved by an applicable 
governmental authority or as otherwise provided for in a jurisdiction where 
approval by an applicable governmental authority is required for a standard to 
go into effect. Where approval by an applicable governmental authority is not 
required, the standard shall become effective on the first day of the first 
calendar quarter that is 18 months after the date the standard is adopted by the 
NERC Board of Trustees or as otherwise provided for in that jurisdiction. 

Draft 2: October 4July 3, 2013   

Page 4 of 26 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
B. Requirements and Measures

Rationale for R1: Total Flowgate Capability (TFC) and Total Transfer Capability (TTC) are the starting points 
for the Available Flowgate Capability (AFC) and Available Transfer Capability (ATC) values. AFC and ATC 
values influence real‐time conditions and have the ability to impact real‐time operations. A Transmission 
Operator (TOP) shall clearly document its methods of determining TFC and TTC so that any TOP or 
Transmission Service Provider (TSP) that uses the information can clearly understand how the values are 
determined. The TFC and TTC values shall account for any reliability constraints that limit those values as 
well as system conditions forecasted for the time period for which those values are determined. The TFC 
and TTC values shall also incorporate constraints on external systems when appropriate, in addition to 
constraints on the TOP’s own system.
Rationale for R1: TFC and TTC values are important to the reliability of the bulk power system when they 
are used to determine AFC and ATC or in the real‐time operation of the transmission system. The 
Transmission Operator needs to calculate a value that protects reliability both on its system and 
neighboring systems. Having a current and accurate description of this process allows neighboring systems 
and their Transmission Service Provider to understand how the values were determined. In addition, if a 
Transmission Operator’s method by default does not monitor one or more constraints on another 
Transmission Operator’s system, then they should describe how they are monitoring those constraints 
when requested to by that affected Transmission Operator. Those off‐system constraints should be 
monitored at a Power Transfer Distribution Factor (PTDF) or Outage Transfer Distribution Factor (OTDF) of 
five percent or less, if appropriate to the means of determining TFC or TTC.   

R1.

Each Transmission Operator that determines Total Flowgate Capability (TFC) or Total Transfer 
Capability (TTC) shall develop a writtenprepare, keep current, and implement a TFC or TTC 
methodology (or methodologies) for determiningcalculating its TFC or TTC values. The methodology 
(or methodologies) shall reflect the Transmission Operator’s current practices for determining TFC or 
TTC values., if: [Violation Risk Factor: Lower] [Time Horizon: Operations Planning] 

1.1.



Used by that Transmission Operator; 



Requested by its Transmission Service Provider(s); or 



Requested by its Reliability Coordinator.  

The methodologies shall include: 

1.1 A statement that the TTC or TFC Each methodology shall describe the method used to account 
for the following limitations in both the pre‐ and post‐contingency state:  
1.1.1

Facilityincorporate facility ratings; 

1.1.2

System, voltage limits; 

1.1.11.1.3
1.1.4

Transient, and stability limits pre‐ and post‐contingency;  

Voltage stability limits; and  

Draft 2: October 4, July 3 2013   

Page 5 of 26

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 


A description of how this is accomplished;  

1.1.5

What criteria (if any) is used to select which of the limits, or Other System Operating 
Limits (SOLs).  



), are relevant to the calculation; and 



The rationale for the selection of the TTC or TFC method being used. 

1.2 The methodologies shall address, at a minimum, Each methodology shall describe the method 
used to account for each of the following elements, provided such elements impact of the 
determination of TFC or TTC calculation: 
1.2.1

TheHow simulation of transfers are performed through the adjustment of generation, 
Load, or both; 

1.2.2

Transmission topology, including, but not limited to, additions and retirements; 

1.2.3

ExpectedCurrently approved and projected transmission uses; 

1.2.4

Planned outages; 

1.2.5

Parallel path (loop flow) adjustments; 

1.2.6

Load forecast; and 

1.2.7

Generator dispatch, including, but not limited to, additions and retirements. 

1.3 Each methodology shall describe the process for includingThe methodologies shall include any 
reliability‐related constraints that are requested to be included by another Transmission 
Operator, provided that (1) the request references this specific requirement, and (2) the 
requesting Transmission Operator includes those constraints are also used in itsthat 
Transmission Operator’s TFC or TTC determinationcalculation. 
1.3.1 Each Transmission Operator that uses the Flowgate Methodology shall include in its 
methodology an impact test process for including requested constraints. If a generator to 
Load transfer in a registered entity’s area or a transfer to a neighboring registered entity 
impact the requested constraint by five percent or greater, the requested constraint shall 
be included in the TFC determination, otherwise the requested constraint is not required 
to be included. 
1.3.2  Each Transmission Operator that uses the Area Interchange or Rated System Path 
Methodology shall describe the process it uses to account for requested constraints that 
have a five percent or greater distribution factor for a transfer between areas in the TTC 
determination; otherwise the requested constraint is not required to be included. When 
testing transfers involving the requesting Transmission Operators area, the requested 
constraint may be excluded.  
1.3.3 A different method for determining whether requested constraints need to be included 
in the TFC or TTC determination may be used if agreed to by the Transmission Operators. 

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1.3.1 The Transmission Operator shall use a distribution factor (Power Transfer Distribution 
Factor (PTDF) or Outage Transfer Distribution Factor (OTDF)) of five percent or less when 
determining if these constraints should be monitored.  
1.2.

The methodologies shall address the periodicity for the Transmission Operator to provide 
updated TFC or TTC values to the Transmission Service Provider. 

M1. Examples of evidence include, but are not limited, to Each Transmission Operator that determines 
TFC or TTC shall provide its current methodology (or methodologies) or other evidence (such as 
written documentation) to show that its methodology (or methodologies) contains the following:  


A description of the method used to account for the limits specified in part 1.1. Methods of 
accounting for these limits may include, but are not limited toinclude, but are not limited to, one 
or more of the following: 
o TFC or TTC being determined by one or more limits. 
o Simulation being used to find the maximum TFC or TTC that remains within the limit. 
o The application of a distribution factor in determining if a limit affects the TFC or TTC value. 
o Monitoring a subset of limits and a statement that those limits are expected to produce the 
most severe results;  
o A statement that the monitoring of a select limit(s) results in the TFC or TTC not exceeding 
another set of limits.   
o A statement that one or more of those limits are not applicable to the TFC or TTC 
determination. 



A dated effective methodology that is posted on the Transmission Operator’s website, or 
their Transmission Service Provider’s website, or on the Open Access Same‐Time Information 
System (OASIS); 



Descriptions within the methodology regarding how constraints identified by another 
Transmission Operator are included and how a distribution factor is applied, or a statement 
that such a request has not been made, or the TTC or TFC calculation does not use PTDF or 
OTDF in the calculation; or 



Language in the TFC or TTC methodology that specifies the periodicity of providing updated 
TFC or TTC values to the Transmission Service Provider and evidence that the updated values 
were provided according to the specified timeframes.  
If the Transmission Operator and Transmission Service Provider are the same entity then 
evidence of limits and a statement that those limits are expected to produce the most severe 
results. 



A description of the method used to account for the elements specified in part 1.2, provided such 
elements impact the determination of TFC or TTC. Methods of accounting for these elements 
may include, but are not limited to, one or more of the following: 

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o A statement that the element is not accounted for since it does not affect the determination 
of TFC or TTC. 
o A description of how the element is used in the determination of TFC or TTC. 



(1.3) A copy of the request and a description of the method used to perform the impact test 
(1.3.1) or account for the requested constraints (1.3.2).  



The Transmission Operator shall also be using their current method to determine TFC or TTC.  
Evidence of this could be, but is not limited to, a demonstration that a selection of currently 
active TFC or TTC values were calculated based on the current methodology.   

Rationale for R2: A TSP must clearly document its methods of determining AFC and ATC so that TOPs can 
clearly understand how the values are determined. The AFC and ATC values shall account for system 
conditions at the time those values would be used. Each TSP that uses the Flowgate Methodology shall 
also use the AFC value determined by the TSP responsible for an external system constraint where 
appropriate.

Rationale for R2:  
ATC is a prediction of the remaining amount of power that can be transferred on a path between two 
systems for defined system conditions. AFC is a prediction of the amount of additional power for defined 
system conditions that could flow over a particular flowgate, which may involve one or more paths 
between systems. The ATC or AFC value influences, to varying degrees depending on the locality, the 
system conditions that the operator inherits in real time, which gives the Transmission Operator and 
others an interest in understanding how the values are calculated. To ensure that the Transmission 
Operator and others have this information, the Transmission Service Provider must have an Available 
Transfer Capability Implementation Document (ATCID) that accurately describes the current process of 
determining this value. 

R2.

   Each Transmission Service Provider that determines Available Flowgate Capability (AFC) or 
Available Transfer Capability (ATC) shall developshall prepare, keep current, and implement an 
Available Transfer Capability Implementation Document (ATCID) that describes the methodology (or 
methodologies) it uses to determine AFC or ATC values. The methodology (or methodologies) shall 
reflect the Transmission Service Provider’s current practices for determining AFC or ATCused to 
calculate ATC or AFC values. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning] 
2.1. Each methodology shall describe the method used to account for the following elements that 
impact the determination of AFC or ATC: 
2.1.1.

The simulation of transfers performed through the adjustment of generation, Load, or 
both; 

2.1.2.

Transmission topology, including, but not limited to, additions and retirements; 

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2.1.3.

Expected transmission uses; 

2.1.4.

Planned outages;  

2.1.5.

Parallel path (loop flow) adjustments; 

2.1.6.

Load forecast; and 

2.1.7.

Generator dispatch, including, but not limited to, additions and retirements. 

2.2. Each Transmission Service Provider that uses the Flowgate Methodology shall, for reliability 
constraints identified in part 1.3, use the AFC determined by the Transmission Service Provider 
for that constraint. 
M2. Examples of evidence, but are not limited to, a dated effective ATCID that is posted on the 
Transmission Service Provider’s website or OASIS and a demonstration that select currently active 
values of ATC were calculated based on its current ATCID.Each Transmission Service Provider that 
determines AFC or ATC shall provide its current ATCID or other evidence (such as written 
documentation) to show that its ATCID contains the following: 


A description of the method used to account for the elements specified in part 2.1, provided such 
elements impact the determination of AFC or ATC. Methods of accounting for these elements 
may include, but are not limited to, one or more of the following: 
o A description of how the element is used in the determination of AFC or ATC. 
o A statement that the element is not accounted for since it does not affect the determination 
of AFC or ATC. 
o A statement that the element is accounted for in the determination of TFC or TTC by the 
Transmission Operator, and does not otherwise affect the determination of AFC or ATC. 



Each Transmission Service Provider that uses the Flowgate Methodology shall provide a 
description of the method in which AFC provided by another Transmission Service Provider was 
used for the reliability constraints identified in part 1.3. 



The Transmission Service Provider shall also be using their current method to determine AFC or 
ATC. Evidence of this could be, but is not limited to, a demonstration that a selection of currently 
active AFC or ATC values were calculated based on the current methodology. 

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Rationale for R3:  
Capacity Benefit Margin (CBM) is one of the values that may be a value used in by a Transmission Service 
Provider when determining ATC. To ensure transparency and reliability, the Transmission Service Provider 
must have a Capacity Benefit Margin Implementation Document (CBMID) that accurately describes the AFC 
or ATC value. CBM is current process of determining this value that can be shared with other entities with a 
reliability need to understand the amount of firm transmission transfer capability preserved by the 
transmission providerTransmission Service Provider’s process for Load‐Serving Entities (LSEs), who’s Loads 
are located on that TSPs system, to enable access bycreating the CBM value. When a Transmission Service 
Provider does not use CBM, the LSEs to generation from interconnected systems to meet resource 
reliability requirements. A clear explanation of how value in the ATC calculation is zero.  The CBM value is 
developed is an important aspect ofcould have been included in the TSPs ability to communicate to TOPs 
howATCID. However, Transmission Service Providers have other obligations (tariffs, contracts, future 
NAESB standards) that AFC or ATC value was determined. Therefore anytime CBM is used (non‐zero) a 
CBMID is required to communicatereference the method of determining CBMCBMID; keeping it as its own 
document seemed to be less burdensome then requiring its inclusion in the ATCID.

  R3.  Each Transmission Service Provider that determines Capacity Benefit Margin (CBM) values shall 
developprepare, keep current, and implement a Capacity Benefit Margin Implementation Document 
(CBMID) that describes its method for establishing CBM. The method described in the CBMID shall 
reflect the Transmission Service Provider’s current practices for determining CBM values. [Violation 
Risk Factor: Lower] [Time Horizon: Operations Planning]margins to protect system reliability during a 
declared NERC Energy Emergency Alert 2 or higher.  

Transmission Service Providers that do not use Capacity Benefit Margin (CBM) shall state this in the 
CBMID. 

M3.  Each Examples Transmission Service Provider that determines CBM, shall provide evidence, 
including, but not limited to, its current CBMID, current CBM values, or other evidence (such as 
written documentation, study reports, or supporting information) to demonstration that it 
established CBM values consistent with its methodology described in its CBMID. If a Transmission 
Service Provider does not maintain CBM, examples of evidence include, but are not limited to, an 
affidavit, statement, or other documentationa dated effective CBMID that is posted on the 
Transmission Service Provider’s website or OASIS and a demonstration, such as a study report, that 
statesselect currently active values of CBM were determined per the CBMID, if the Transmission 
Service Provider does not maintainProviders uses CBM.  

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Rationale for R4:  
Transmission Reliability Margin (TRM) is one of the values that may be used in additional capacity held by a 
Transmission Service Provider when determining the AFC or ATC value. TRM accounts for the inherent 
uncertainty in system conditions and the need forproviding additional operating flexibilitymargin to a 
Transmission Operator. To ensure reliable system operation as system conditions change. An explanation 
by the TOP of how the TRM value is developed for use in the TSP’s determination of AFCtransparency and 
ATC is an important aspect of the TSP’s ability to communicate to TOPs how that AFC or ATC value was 
determined. Therefore, anytime a TOP provides a non‐zero TRM to a TSP,reliability, the Transmission 
Operator must have a Transmission Reliability Margin Implementation Document (TRMID) is required to 
communicate the methodthat accurately describes their current process of determining TRM.this value 
and can be shared with entities that have a reliability need to understand the Transmission Operator’s 
process for creating the TRM value. When a Transmission Service Provider does not utilize TRM, the value 
in the ATC calculation is zero.  

R4. Each Transmission Operator that determines Transmission Reliability Margin (TRM) values shall 
developprepare, keep current, and implement a Transmission Reliability Margin Implementation 
Document (TRMID) that describes its method for establishing TRM. The method described in the 
TRMID shall reflect the Transmission Operator’s current practices for determining TRM values. 
[Violation Risk Factor: Lower][Time Horizon: Operations Planning]margins to protect system 
reliability.  

Transmission Operators that do not use Transmission Reliability Margin (TRM) shall state this in 
the TRMID.  

M4.   Examples ofEach Transmission Operator that determines TRM shall provide evidence 
includeincluding, but are not limited to, its currenta dated TRMID, current TRM values, or other 
evidence (such as written documentation, study reports, or supporting information) to 
demonstrate that it established TRM values consistent with its methodology described in the 
TRMID.  If a Transmission Operator does not maintain TRM, examples of evidence include, but are 
not limited to, an affidavit, statement, or other documentation that states the Transmission 
Operator does not maintain TRM.that is posted on the Transmission Operator’s website or OASIS 
and a demonstration, such as a study report, that select currently active values of TRM were 
determined per the TRMID, if the Transmission Operator uses TRM.  

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Rationale for R5: Clear communication of the methods of determining AFC, ATC, CBM, TFC, TRM, and TTC 
are necessary to the reliable operation of the Bulk‐Power System (BPS). A TOP and TSP are obligated to 
make available their methodologies for determining AFC, ATC, CBM, TFC, TRM, and TTC to those with a 
reliability need. The TOP and TSP are further obligated to respond to any requests for clarification on those 
methodologies, provided that responding to such requests would not be contrary to the registered entities 
confidentiality, regulatory, or security concerns. The purpose of this requirement is not to monitor every 
communication that occurs regarding these values, but to ensure that those with reliability need have 
access to the information. Therefore, the requirement is very specific on when it is invoked so that it does 
not create an administrative burden on regular communications between registered entities. 
Rationale for R5:  
One of this standard’s primary goals is transparency in the methods used to determine ATC or AFC. To  
support that goal, this requirement requires the Transmission Service Provider and Transmission Operator  
to share their implementation document (if not already posted publicly) and respond to questions when  
asked in writing to do so under the standard. This requirement establishes a threshold for a question to fall  
under the requirement, so that routine and customary discussions do not need to be documented 

R5. Within 4530 calendar days of receiving a written request that references this specific requirement 
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission 
Planner, Transmission Service Provider, or any other registered entity that demonstrates a 
reliability need, each Transmission Operator or Transmission Service Provider and Transmission 
Operator (subject to confidentiality, regulatory, or security requirements) shall provide: [Violation 
Risk Factor: Lower] [Time Horizon: Operations Planning] 
5.1.

A written response to any request for clarification of its TFCATC or TTCAFC methodology, 
ATCID, CBMID, or TRMID. If the request for clarification is contrary to the Transmission 
Operator’s or Transmission Service Provider’s confidentiality, regulatory, or security 
requirements then a written response shall be provided explaining the clarifications not 
provided, on what basis and whether there are any options for resolving any of the 
confidentiality, regulatory, or security concerns. 

5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s 
effective: 
5.2.1 TRMIDCBMID; and 
5.2.2 TFC or TTC methodology. 

5.3.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s 
effective: 
5.3.1 ATCID; and 
5.3.2 TRMIDCBMID. 

M5. Examples of evidence include, but are not limited to, dated records of the request from a Planning 
Coordinator, Reliability Coordinator, Transmission Operator, Transmission Planner, Transmission 
Service Provider, or another registered entity who demonstrates a reliability need; the 
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Transmission Service Provider’s response to the request; and a statement by the Transmission 
Service Provider that they have received no requests.: 


Dated records of the request and the Transmission Operator’s or Transmission Service 
Provider’s response to the request;  



A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests; or  



A statement by the Transmission Operator or Transmission Service Provider that they do not 
determine one or more of these values: AFC, ATC, CBM, TFC, TTC or TRM.  

Rationale for R6: This requirement provides a mechanism for each TOP or TSP to access the best available data 
for use in its calculation of AFC, ATC, CBM, TFC, TRM, and TTC values. Requirement R6 requires that a TOP and 
TSP share their data, with the caveat that the TOP and TSP is not required to modify that data from the form 
that they use or maintain it in. For data requests that involve providing data on a regular interval, the TOP and 
TSP is not obligated to provide the data more frequently than either (1) once an hour, or (2) as often as they 
update the data. The data provider is also not obligated to provide data that would violate any of its 
confidentiality, regulatory, or security obligations. The purpose of this requirement is not to monitor every data 
exchange that occurs regarding these values, but to ensure that those with reliability need have access to the 
information. Therefore, the requirement is very specific on when it is invoked so that it does not create an 
administrative burden on regular communications between registered entities. 
Rationale for R6:  
A Transmission Service Provider or Transmission Operator may need data (e.g., load forecast, expected  
dispatch, planned outages) from its neighbor in order to accurately calculate TTC, TFC, ATC, or AFC values.  
This requirement allows them to pursue accessing that data with the limitation that the owner of the data  
is not obligated to modify it for another entity’s use, nor provide data that is otherwise accessible. This  
requirement should not discourage data exchanges and data requests, especially those already in place.  
Therefore, the requirement is specific in that it is invoked only when specifically invoked by the requestor  
and assumes that there may have been other attempts to get the data that were unsuccessful. 

R6. Within 30 days of a written request that references this requirement from another Transmission 
Service Provider or Transmission Operator, a Transmission Service Provider or Transmission 
Operator shall share data used in their respective AFC, ATC, TFC, or TTC calculations (subject to 
confidentiality, regulatory, or security requirements. [Violation Risk Factor: Lower] [Time Horizon: 
Operations Planning] 
6.1.

To be valid, the request must specify that the data is for use in the requesting party’s AFC, 
ATC, TFC, or TTC calculations.  

6.2.

The Transmission Service Provider and Transmission Operator are not required to modify 
the data from the format in which they maintain, use, or currently make available the data. 

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MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
R7.R6. Each Transmission Operator or Transmission Service Provider that receives a written request 
from another Transmission Operator or Transmission Service Provider for data related to AFC, 
ATC, TFC, or TTC determinations that (1) references this specific requirement, and (2) specifies that 
the requested data is for use in the requesting party’s AFC, ATC, TFC, or TTC determination shall 
take one of the actions below.  
6.1. In responding to a written request for data on an ongoing basis, the Transmission Service 
Provider or Transmission Operator shall make available its data on an ongoing basis no later 
than 45 days from receipt of the written request. Unless otherwise agreed upon, the 
Transmission Operator or Transmission Service Provider is not required to: 
6.1.1 Alter the format in which it maintains or uses the data; or 
6.1.2 Make available the requested data on a more frequent basis than it produces the 
data and in no event shall it be required to provide the data more frequently than 
once an hour. 
6.2 In responding to all other data requests, each Transmission Operator or Transmission Service 
Provider shall make available the requested data within 45 days of receipt of the written 
request. Unless otherwise agreed upon, the Transmission Operator or Transmission Service 
Provider is not required to alter the format in which it maintains or uses the data.
6.3 If making available any requested data under parts 6.1 or 6.2 of this requirement is contrary 
to the Transmission Operator’s or Transmission Service Provider’s confidentiality, regulatory, 
or security requirements, the Transmission Operator or Transmission Service Provider shall 
not be required to make available that data; provided that, within 45 days of the written 
request, it responds to the requesting registered entity specifying the data that is not being 
provided, on what basis and whether there are any options for resolving any of the 
confidentiality, regulatory or security concerns.   
M6. Examples of evidence for a data request that involves providing data at regular intervals on an 
ongoing basis (6.1), include, but are not limited to: 


Dated records of a registered entity’s request, and examples of the response being met and 
the Transmission Service Provider’s or Transmission Operator’s response to the request;  



Dated records of a registered entity’s request, a statement from the requestor that the 
request was met (demonstration that the response was met is not required if the requestor 
confirms it is being provided) A statement from the requestor that the request was met; or 



A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests under this requirement.  

Examples of evidence for all other data requests (6.2) In the case of a data request that involves 
the providing of data on regular intervals, examples of evidence include, but are not limited to:  


Dated records of a registered entity’s request, and the response to the request;  



Dated records of a registered entity’s request, a statement from the requestor that the 
request was met Examples of the Transmission Service Provider or Transmission Operator 
providing the data at intervals; or 

Draft 2: October 4, July 3 2013   

Page 14 of 26

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 


A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests under this requirement. A statement from the requestor that the 
request is being met. 

An example of evidence of a response by the Transmission Operator or Transmission Service 
Provider that providing the data would be contrary to the registered entity’s confidentiality, 
regulatory, or security requirements (6.3) includes a response to the requestor specifying the data 
that is not being provided, on what basis and whether there are any options for resolving any of 
the confidentiality, regulatory, or security concerns. 

Draft 2: October 4, July 3 2013   

Page 15 of 26

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
C. Compliance

1.

Compliance Monitoring Process: 
1.1. Compliance Enforcement Authority: 
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” 
refers to NERC or the Regional Entity in their respective roles of monitoring and 
enforcing compliance with the NERC Reliability Standards. 
1.2. Evidence Retention:  
The following evidence retention periods identify the period of time a registeredan 
entity is required to retain specific evidence to demonstrate compliance. For 
instances in which the evidence retention period specified below is shorter than the 
time since the last audit, the Compliance Enforcement Authority may ask the 
registered entity to provide other evidence to show that it was compliant for the full 
time period since the last audit.  


Implementation and methodology documents shall be retained for five years. 



Components of the calculationsCalculations and the results of such calculations 
for all values contained in theother components of implementation and 
methodology documents. shall be retained to show compliance in calculating: 
o Hourly values for the most recent 14 days;  
o Daily values for the most recent 30 days; and  
o Monthly values for the most recent 60 days. 



If a Transmission Operator or Transmission Service Provider responsible entity is 
found non‐compliant, it shall keep information related to the non‐compliance 
until mitigation is complete and approved. 



The Compliance Enforcement Authority shall keep the last audit records and all 
requested and submitted subsequent audit records.  

1.3. Compliance Monitoring and Assessment Processes: 


As defined in the NERC Rules of Procedure, “Compliance Monitoring and 
Assessment Processes” refers to the identification of the processes that will be 
used to evaluate data or information for the purpose of assessing performance 
or outcomes with the associated reliability standard. 

1.4. Additional Compliance Information: 


None 

Draft 2: October 4, July 3, 2013 

Page 16 of 26 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 


D. Regional Variances

None. 
E. Interpretations

None. 
F. Associated Documents

None. 
Table of Compliance Elements
R # 

Time 
Horizon 

VRF 

R1  Operations  Lower 
Planning 

Draft 2: October 4, July 3, 2013 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

High VSL 

EachThe Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for one of the 
limitations listed in 
part 1.1 in its 
writtenprepared, kept 
current, and implemented a 
methodology. (1.1) 

OR 

Each  that is used by its 
Transmission Operator 
that determines TFC or 

EachThe Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for two of the 
limitations listed in 
part 1.1 in its 
writtenprepared, kept 
current, and implemented a 
methodology. (1.1) 

OR  

Each  that is used by its 
Transmission Operator 
that determines TFC or 

EachThe Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for any of the 
limitations listed in 
part 1.1 in its written 

Severe VSL 

EachThe Transmission 
Operator that 
determines TFC or TTC 
did not developprepare, 
keep current, or implement 
a written methodology 
for describing its 
current practices for 
prepared, kept current, and  determining TFC or TTC 
implemented a 
values. 
methodology. (1.1) 

OR 
OR 

Each Transmission 
Each  that is used by its 
Operator that uses TFC 
Transmission Operator  or TTC developed a 
that determines TFC or  written methodology 
Page 17 of 26 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

TTC has not described 
its method for 
accounting for one of 
the element listed in 
part 1.2 in its written 
methodology, provided 
that element impacts 
its TFC or TTC 
determination. (1.2) 

TTC has not described 
its method for 
accounting for two, 
three, or four elements 
listed in part 1.2 in its 
written methodology, 
provided those 
elements impacts its 
TFC or TTC 
determination. 
(1.2)Service Provider, but 

Service Provider, but does 
not address one of the 
requirement parts. 

Draft 2: October 4, July 3, 2013 

High VSL 

TTC has not described 
its method for 
accounting for five, six, 
or seven elements of 
listed in part 1.2 in its 
written methodology, 
provided those 
elements impacts its 
TFC or TTC 
determination. (1.2) 

does not address two of the  OR 
requirement parts. 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described the 
process for including 
any reliability‐related 
constraints that have 
been requested by 
another Transmission 
Operator, provided the 
constraints are also 
used in the requesting 
Transmission 
Operator’s TFC or TTC 
calculation and the 
request referenced 
Page 18 of 26 

Severe VSL 
for determining TFC or 
TTC but the 
methodology did not 
reflect its current 
practices for 
determining TFC or TTC 
values. 
. 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

High VSL 
part 1.3. (1.3) 

OR  

Each Transmission 
Operator that 
determines TFC or TTC 
has not used (i) an 
impact test process for 
including requested 
constraints, (ii) a 
process to account for 
requested constraints 
that have a five 
percent or greater 
distribution factor for a 
transfer between areas 
in the TTC 
determination, or (iii) a 
mutually agreed upon 
method for 
determining whether 
requested constraints 
need to be included in 
the TFC or TTC 
determination. (1.3.1, 
1.3.2, 1.3.3)Service 
Provider, but does not 
address three of the 

Draft 2: October 4, July 3, 2013 

Page 19 of 26 

Severe VSL 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

requirement parts.

R2  Operations  Lower 
Planning 

Draft 2: October 4, July 3, 2013 

Each Transmission 
Service Provider that 
determines AFC or ATC 
has not described its 
method for accounting 
for one of the elements 
listed in part 2.1 in its 
written methodology, 
provided that element 
impacts its AFC or ATC 
determination. (2.1) 

None. 

Each Transmission 
Service Provider that 
determines AFC or ATC 
has not described its 
method for accounting 
for two, three, or four 
elements listed in part 
2.1 in its written 
methodology, provided 
the elements impact its 
AFC or ATC 
determination. (2.1) 
None. 

Each Transmission 
Service Provider that 
determines AFC or ATC 
has not described its 
method for accounting 
for five, six, or seven 
elements listed in part 
2.1 in its written 
methodology, provided 
the elements impact its 
AFC or ATC 
determination. (2.1) 

OR 

Each Transmission 
Service Provider that 
uses the Flowgate 
Methodology did not 
use the AFC 
determined by the 
Transmission Service 
Provider for reliability 
constraints identified 
Page 20 of 26 

EachThe Transmission 
Service Provider that 
determines AFC or ATC 
didhas not 
developprepared an 
ATCID describing its 
AFC or ATC 
methodology. 

OR 
Each 
The Transmission 
Service Provider that 
determines AFC or ATC 
didhas not reflect 
itskept current practices 
for determining AFC or 
ATC values in itsan 
ATCID. 

OR 

The Transmission Service 
Provider has not 
implemented an ATCID.

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R3  Operations  Lower 
Planning  

None. 

Moderate VSL 
None. 

High VSL 
in part 1.3. (2.2)None. 
None. 

Severe VSL 
EachThe Transmission 
Service Provider that 
uses CBM values didhas 
not developprepared a 
CBMID describing its 
method for 
determining CBM 
values. 

OR 

EachThe Transmission 
Service Provider that 
uses CBM values didhas 
not reflect itskept 
current practices for 
determining CBM 
values in itsa CBMID. 

OR 

The Transmission Service 
Provider has not 
implemented a CBMID. 

Draft 2: October 4, July 3, 2013 

Page 21 of 26 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R4  Operations  Lower 
Planning 

None. 

Moderate VSL 
None. 

High VSL 
None. 

Severe VSL 
EachThe Transmission 
Operator that uses 
TRM values didhas not 
developprepared a 
TRMID describing its 
method for 
determining TRM 
values. 

OR 

EachThe Transmission 
Operator that uses 
TRM values didhas not 
reflect itskept current 
practices for 
determining TRM 
values in itsa TRMID. 

OR 

The Transmission Operator 
has not implemented a 

R5  Operations  Lower 
Planning 

Draft 2: October 4, July 3, 2013 

Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respondThe responsible 
entity responds to a 

Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respondThe responsible 
entity responds to a 

Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respondThe responsible 
entity responds to a 
Page 22 of 26 

TRMID. 
Each Transmission 
Operator or 
Transmission Service 
Provider failedThe 
responsible entity fails to 
respond to a written 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

R6  Operations  Lower 
Planning 

Draft 2: October 4, July 3, 2013 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

written request by one 
or more of the 
registered entities 
specified in 
Requirementrequirement 
R5 within 45 in 31 or 
more calendar days 
from the date of the 
request, but did 
respond within 75not 
more than 60 calendar 
days after the request. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respondThe responsible 
entity responds to a 
written request for 
data by one or more of 
the registered entities 
specified in 
Requirementrequirement 
R6 by making the 
requestedto share data 
available withinused in 
45their TTC or ATC 
calculation in 31 or more 
calendar days from the 

written request by one 
or more of the 
registered entities 
specified in 
Requirementrequirement 
R5 within 76 in 61 or 
more calendar days 
from the date of the 
request, but did 
respond within 105not 
more than 90 calendar 
days after the request. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respondThe responsible 
entity responds to a 
written request for 
data by one or more of 
the registered entities 
specified in 
Requirementrequirement 
R6 by making data 
available within 76to 

High VSL 

written request by one 
or more of the 
registered entities 
specified in 
Requirementrequirement 
R5 within 106 in 91 or 
more calendar days 
from the date of the 
request, but did 
respond within135not 
more than 120 calendar 
days after the request. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respondThe responsible 
entity responds to a 
written request by one 
or more of the 
registered entities 
specified in 
Requirementrequirement 
R6 by makingto share 
data available within 
share data used in their TTC  106used in their TTC or 
or ATC calculation in 61 or 
more calendar days 

ATC calculation in 91 or 
more calendar days 

from the date of the 

from the date of the 
Page 23 of 26 

Severe VSL 
request by one or 
more of the entities 
specified in 
Requirementrequirement 
R5. 

Each Transmission 
Operator or 
Transmission Service 
Provider failedThe 
responsible entity fails to 
respond to a written 
request for data by 
making data available 
toby one or more of the 
entities specified in 
Requirementrequirement 
R6. 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 
date of the request, 
but did respond within 
75not more than 60 
calendar days after the 
request. 

Draft 2: October 4, July 3, 2013 

Moderate VSL 
request, but did 
respond within 105not 
more than 90 calendar 
days after the request. 

High VSL 
request, but did 
respond within 135not 
more than 120 calendar 
days after the request. 

Page 24 of 26 

Severe VSL 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

D. Regional Variances

None. 
E. Interpretations

None. 
F. Associated Documents

None. 

Draft 2: October 4 July 3, 2013 

Page 25 of 26

Application Guidelines 
Guidelines and Technical Basis
Please see the MOD A White Paper for further information regarding the technical basis for 
each requirement.

Draft 2: October 4July 3, 2013 

Page 26 of 26 

Implementation Plan
Project 2012-05 MOD A
Implementation Plan for MOD-001-2 – Available Transmission System Capability
Approvals Required
MOD-001-2 – Available Transmission System Capability
Prerequisite Approvals
There are no other standards that must receive approval prior to the approval of this standard.
Revisions to Glossary Terms
None
Applicable Entities
Transmission Operator
Transmission Service Provider
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
The standard shall become effective on the first day of the first calendar quarter that is 18 months
after the date that the standard is approved by an applicable governmental authority or as otherwise
provided for in a jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not required,
the standard shall become effective on the first day of the first calendar quarter that is 18 months after
the date the standard is adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.
Justification
The proposed 18-month implementation period is designed to allow the North American Energy
Standards Board (NAESB) to include in its Wholesale Electric Quadrant Standards for Business Practices
and Communication Protocols for Public Utilities (WEQ Standards), prior to the effective date of

proposed MOD-001-2 and the retirement of currently effective Reliability Standards MOD-001-1, MOD004-1, MOD-008-1, MOD-028-2, MOD-029-1a and MOD-030-2 (MOD A Standards), those elements
from the MOD A Standards that relate to commercial or business practices and are not included in
proposed MOD-001-2. NERC and the standard drafting team recognize that even though certain of the
requirements in the MOD A Standards do not address reliability issues and, in turn, are not included in
proposed MOD-001-2, those requirements may be essential for market or commercial purposes and
should be considered by an organization, like NAESB, that administers business practice standards for
the electric industry.
The proposed implementation period should provide NAESB sufficient time, working through its
business practice development process, to adopt revised WEQ Standards to include the commercial
elements of the MOD A Standards and for the Federal Energy Regulatory Commission to incorporate by
reference the revised WEQ Standards into its regulations. NERC expects that NAESB will adopt revised
WEQ Standards to become effective on the same date as the proposed MOD-001-2 and the retirement
of the MOD A Standards will become effective.
Retirements
MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and MOD-030-2 shall be retired at
midnight of the day immediately prior to the effective date of MOD-001-2. The effective retirement
date should coincide with the effective date of revised WEQ Standards adopted by NAESB.

Project 2012-05 ATC Revisions
October 4, 2013

2

Implementation Plan
Project 2012-05 MOD A
Implementation Plan for MOD-001-2 – Available Transmission System Capability
Approvals Required
MOD-001-2 – Available Transmission System Capability
Prerequisite Approvals
There are no other standards that must receive approval prior to the approval of this standard.
Revisions to Glossary Terms
None
Applicable Entities
Transmission Operator
Transmission Service Provider
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
The standardMOD-001-2 shall become effective on as follows:
1. MOD-001-2 shall become effective the first day of the firstseventh calendar quarter that is 18
months after the effective date thatof the standard is approved by anorder providing applicable
governmental authority or as otherwise provided for in a jurisdiction where regulatory approval
by an applicable governmental authority .
In those jurisdictions where no regulatory approval is required for a standard to go into effect. Where
approval by an applicable governmental authority is not required, the standard, MOD-001-2 shall
become effective on the first day of the firstfifth calendar quarter that is 18 months after the date the
standard is adopted by the NERC Board of TrusteesTrustees’ approval, or as otherwise provided for in
that jurisdictionmade effective pursuant to the laws applicable to such ERO governmental authorities.

Justification
The proposed 18-month implementation period is designed to allowNERC is working with the North
American Energy Standards Board (NAESB) to include in its Wholesale Electric Quadrant Standards for
Business Practices and Communication Protocols for Public Utilities (WEQ Standards), prior to the
effective date of proposed MOD-001-2 and the retirement of currently effective Reliability Standards
MOD-001-1, MOD-004-1, MOD-008-1, MOD-028-2, MOD-029-1a and MOD-030-2 (MOD A
Standards),transition those elements fromof the MOD A Standardsexisting standards that relate to
commercial or business practices and arewill not included in proposed MOD-001-2. NERC and the
standard drafting team recognize that even though certain of the requirements in the MOD A
Standards do not address reliability issues and, in turn, are not included in proposed MOD-001-2, those
requirements may be essential for market or commercial purposes and should be considered by an
organization, like NAESB, that administersretained in MOD-001-2 from the NERC Reliability Standards
to NAESB’s business practice standards for the electric industry.
. The proposed18-month implementation period shouldwill provide NAESB sufficient time for NAESB,
working through its business practice development process, to adopt revised WEQ Standards to
include the commercial elements of the MOD A Standards and for the Federal Energy Regulatory
Commission to incorporate by reference the revised WEQ Standards into its regulations.standards that
address the requirements proposed for retirement. NERC expects that NAESB will following Board of
Trustee approval of the proposed standard, NERC will submit a request to NAESB to adopt revised
WEQ Standards to become effective on the same date as thestandards proposed MOD-001-2 and
theor retirement of the MOD A Standards will become effective.into their commercial and business
practice standards and to consider the commission directives associated with those standards. NERC
expects that in adopting the standards to be retired, NAESB will provide for an effective date that will
coincide with the effective date proposed in MOD-001-2.
Retirements
MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and MOD-030-2 shall be retired at
midnight of the day immediately prior to the effective date of MOD-001-2. The effective retirement
date should coincide with the effective date of revised WEQ Standards adopted by NAESB.upon MOD001-2 becoming effective.

Project 2012-05 ATC Revisions Implementation Plan
October 4July 3, 2013

2

Unofficial Comment Form
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2 (Available Transmission System Capability)
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard. The electronic comment form must be completed by 8:00 p.m. ET Monday,
November 18, 2013.
If you have questions please contact Ryan Stewart or by telephone at 404-446-2569.
The project page may be accessed by clicking here.
Background Information

The Project 2012-05 ATC Revisions (MOD A) Standard Drafting Team posted an initial draft of the
Standard MOD-001-2 (Available Transmission System Capability) for comment from July 9 to August 27,
2013. The drafting team has revised the standard based on stakeholder comments and suggestions that
the drafting team considered appropriate. The following is a summary of changes the drafting team has
made:


Revising Requirement R1 to make the applicability clear that it is for those Transmission Operators
(TOPs) that determine Total Flowgate Capability (TFC) or Total Transfer Capability (TTC)



Revising Requirements R1 and R2 to capture reliability-based requirements in determining
Available Flowgate Capability (AFC), Available Transfer Capability (ATC), TFC, or TTC in an entity’s
implementation document.



Revising Requirements R3 and R4 to not force an entity who does not determine Capacity Benefit
Margin (CBM) or Transmission Reliability Margin (TRM) to maintain an implementation document
to simply state the entity does not determine CBM or TRM.



Modified all the Measures to expand the examples of evidence.

This posting solicits comments on the revised MOD-001-2 standard. The standard responds to FERC Order
729, as well as recommendations from the Independent Experts Review Panel, usage of the Paragraph 81
criteria in eliminating certain business practice requirements, and lessons learned from compliance
history.

Questions on MOD-001-2

1. The drafting team has revised MOD-001-2 in response to stakeholder comments and suggestions. If
you do not agree or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments.
Yes
No
Comments:
2. If you have any other comments for the drafting team to consider that you have not already
mentioned, please provide them here:
Comments:

Unofficial Comment Form
Project 2012-05 ATC Revisions (MOD A) | October 2013

2

Compliance Operations

Draft Reliability Standard Compliance Guidance for MOD-001-2
October 21, 2013
Introduction
The NERC Compliance department (Compliance) worked with the MOD A standard drafting team (SDT) to review
the proposed standard MOD-001-2. The purpose of the review was to discuss the requirements of the proposed
standard to obtain an understanding of its intended purpose and the evidence necessary to support compliance.
The purpose of this document is to address specific questions posed by the MOD A SDT in order to aid in the
drafting of the requirements and provide a level of understanding regarding evidentiary support necessary to
demonstrate compliance.
While all compliance evaluations require levels of auditor judgment, participating in these reviews allows
Compliance to develop training and approaches to support a high level of consistency in audits conducted by the
Regional Entities. The following questions and answers are intended to assist the SDT in further refining the
standard and to serve as a resource in the development of training for auditors.
MOD-001-2 Questions
Question 1
In Requirements R1, R2, R3, and R4, what is meant by “current” practices and methodologies in determining
various values and what will an auditor need to see to meet the compliance aspects of the requirements?
Compliance Response to Question 1
With regards to “current” practices, the auditor will focus on the last determined value for each requirement and
the method the entity used to determine that value. The auditor may also ask for a forward looking demonstration
of the value to determine that the registered entity follows its methodology to determine the given value.

Question 2
How will an auditor verify whether a Transmission Operator determines TFC or TTC values (R1) or that a
Transmission Service Provider determines AFC or ATC values (R2)?
Compliance Response to Question 2
Although a registered entity may meet the registration criteria to be registered as a Transmission Operator, there
are instances where that Transmission Operator does not determine TFC or TTC values. Similarly, a registered entity
may meet the registration criteria to be registered as a Transmission Service Provider, there are instances where
that Transmission Service Provider does not determine AFC or ATC. In these instances, as the registered entity does
not determine these values, it would therefore not be unable to fulfill the requirements.
An auditor will first come to an understanding of how the entity operates and whether they determine TFC or TTC.
In the event that it is clear to the auditor that the entity does not determine TFC or TTC, this will be sufficient
evidence for the auditor that the appropriate requirements are not applicable to that entity. In the event that it is
less clear, the auditor will look to see whether the entity operates facilities that are used by a Transmission Service

Provider for transmission service or a monitored path or Flowgate elements to establish whether the requirement
is applicable. If questions remain after this verification, the auditor could look to neighboring entities for
confirmation.
Question 3
Originally, the MOD A ad hoc group included clauses within Requirements R3 and R4 for those registered entities
that do not determine CBM or TRM to state that within its CBMID or TRMID. In consideration of comments, the SDT
removed that language as it met the Paragraph 81 criteria of an administrative burden. Therefore, how will an
auditor verify that those registered entities do not determine CBM or TRM?
Compliance Response to Question 3
An auditor will be looking for an attestation that the registered entity does not determine CBM (R3) or TRM (R4)
and may further look into the registered entity’s ATC equations for previous determined values to see that CBM or
TRM values are not determined.
This approach to compliance assessment is supported in FERC Order 729 at P 298, FERC stated, “though MOD-004-1
[CBM] is not as explicit with regard to its applicability, we believe that its applicability is implicitly reserved to those
entities that maintain capacity benefit margin. Thus, it does not appear that Entergy, or any other entity, would be
in violation of MOD-004-1 [CBM] or MOD-008-1 [TRM] if it does not maintain transmission reliability margin or
capacity benefit margin.”
Conclusion
Following final approval of the Reliability Standard, Compliance will develop the final Reliability Standards Auditor
Worksheet (RSAW) and associated training. Attachment A represents the version of the proposed standard
requirements referenced in this document.

Draft Reliability Standard Compliance Guidance for MOD-001-2
October 21, 2013

2

Standards Authorization Request Form
When completed, please email this form to:

[email protected]

NERC welcomes suggestions to improve the
reliability of the bulk power system through
improved reliability standards. Please use this form
to submit your request to propose a new or a
revision to a NERC’s Reliability Standard.

Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard:

Available Transmission System Capability

Date Submitted:

Revised: September 25, 2013
Original: July 3, 2013

SAR Requester Information
Name:

Ryan Stewart

Organization:

NERC

Telephone:

404-446-2569

E-mail:

[email protected]

SAR Type (Check as many as applicable)
New Standard

Withdrawal of existing Standard

Revision to existing Standard

Urgent Action

SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
The industry need is to resolve FERC directives, incorporate lessons learned, update standards, and to
incorporate initiatives such as results-based, Paragraph 81, etc. The industry is also reviewing the
assessments and recommendations of the Independent Experts Review Panel in support of
transforming the existing set of NERC Reliability Standards to steady-state.

Standards Authorization Request Form

SAR Information
Purpose or Goal (How does this request propose to address the problem described above?):
The SAR proposed modifying standards MOD-001, MOD-004, MOD-008, MOD-028, MOD-029, and
MOD-030 by combining them into one standard by consolidating the reliability components of the
existing standards, retiring the administrative components and transferring market-based requirements
out of the NERC Reliability Standards.
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
The objectives are to address the outstanding directives from FERC Order 729, remove administrative
and market-based requirements from the requirements, and, as possible, incorporate lessons learned.
Lessons learned include best practices by entities, compliance audit experiences with regard to clear
requirements and measures, and growth and maturity in the methods for determining Total Transfer
Capability (TTC), Total Flowgate Capability (TFC), Transmission Reliability Margin (TRM), Capacity Benefit
Margin (CBM), Available Transfer Capability (ATC) and Available Flowgate Capability (AFC).
Brief Description (Provide a paragraph that describes the scope of this standard action.)
Develop a single standard that consolidates the existing MOD-001-1a, MOD-004-1, MOD-008-1, MOD028-1, MOD-029-1a, and MOD-030-2 into a single standard that covers the reliability-related impact of
ATC and AFC calculations, such as the need for Transmission Service Providers to implement their ATC
or AFC calculations in a consistent manner and share ATC or AFC data with their neighboring
Transmission Service Providers or other entities who need such data for reliability purposes.
The requirements are placed within a new version of MOD-001 (MOD-001-2).
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
Detailed description of this project can be found in the Technical White Paper of the original SAR
submittal package.
NERC is working with the North American Energy Standards Board (NAESB) to affect a transfer of the
requirements in the currently effective Reliability Standards MOD-001-1, MOD-004-1, MOD-008-1,

Project 2012-05 Standards Authorization Request
September 25, 2013

2

Standards Authorization Request Form

SAR Information
MOD-028-2, MOD-029-1a and MOD-030-2 (i.e., the MOD A Standards) that are not included in
proposed MOD-001-2 to NAESB to be reviewed for possible inclusion in NAESB’s business practice
standards. NERC and the Project 2012-05 ATC Revisions standard drafting team recognize that even if
certain requirements in the existing MOD A Standards do not address reliability issues and, in turn, are
not included in proposed MOD-001-2, those requirements or components within them may be essential
for market or competition purposes and should be transitioned to an organization that focuses on
market-based standards. Given its role in developing commercial business practices for the electricity
industry, NAESB is likely to be selected by FERC as the appropriate organization to review the
requirements in the currently effective MOD A Standards that are not included in proposed MOD-001-2.

Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization

Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.

Interchange Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.

Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.

Project 2012-05 Standards Authorization Request
September 25, 2013

3

Standards Authorization Request Form

Reliability Functions
Transmission Service
Provider

Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).

Transmission Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling
Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market Operator

Interface point for reliability functions with commercial functions.

Load-Serving Entity

Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.

Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.

Project 2012-05 Standards Authorization Request
September 25, 2013

4

Standards Authorization Request Form

Reliability and Market Interface Principles
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
Yes
Yes
Yes

Yes

Related Standards
Standard No.

Explanation

MOD-001-1a

Available Transmission System Capability

MOD-004-1

Capacity Benefit Margin

MOD-008-1

Transmission Reliability Margin Calculation Methodology

MOD-028-1

Area Interchange Methodology

MOD-029-1a

Rated System Path Methodology

MOD-030-2

Flowgate Methodology

Related SARs
SAR ID

Explanation

Project 2012-05 Standards Authorization Request
September 25, 2013

5

Standards Authorization Request Form

Related SARs

Regional Variances
Region

Explanation

ERCOT

FERC Order No. 729 at P 298 states: “…it is appropriate to exempt entities within ERCOT from
complying with these Reliability Standards. We agree that, due to physical differences of
ERCOT’s transmission system, the MOD Reliability Standards approved herein would not
provide any reliability benefit within ERCOT.”

FRCC

None

MRO

None

NPCC

None

RFC

None

SERC

None

SPP

None

WECC

None

Project 2012-05 Standards Authorization Request
September 25, 2013

6

Standards Authorization Request Form
When completed, please email this form to:

[email protected]

NERC welcomes suggestions to improve the
reliability of the bulk power system through
improved reliability standards. Please use this form
to submit your request to propose a new or a
revision to a NERC’s Reliability Standard.

Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard:

Available Transmission System Capability

Date Submitted:

July 3Original: July 3, 2013
Revised: September 25, 2013

SAR Requester Information
Name:

Ryan Stewart

Organization:

NERC

Telephone:

404-446-2569

E-mail:

[email protected]

SAR Type (Check as many as applicable)
New Standard

Withdrawal of existing Standard

Revision to existing Standard

Urgent Action

SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
Resolve The industry need is to resolve FERC directives, incorporate lessons learned, update standards,
and to incorporate ERO initiatives, including drafting such as results-based ,or, performance-based,
standards consistent with Paragraph 81 , etcriteria. The industry need is to also reviewing the
assessments and recommendations of the Independent Experts Review Panel in support of
transforming the existing set of NERC Reliability Standards into steady-state. The industry reliability
need is to ensure that determinations of available transfer capability are accomplished in a manner that

SAR Information
supports the reliable operation of the Bulk Power System, etc.
Purpose or Goal (How does this request propose to address the problem described above?):
The pro forma standardSAR proposeds (1) modifying standards MOD-001, MOD-004, MOD-008, MOD028, MOD-029, and MOD-030 by cominingconsolidating them into onea single standard by consolidates
consolidatingfocused exclusively on the reliability components of the existing standards and retires (2)
transferring the market-based requirements to another organization, like NAESB, that administers
business practice standards for the electric industry.
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
The objectives are to address the outstanding directives from FERC Order 729, remove market-based
requirements from the requirements, and incorporate lessons learned. Lessons learned include best
practices by entities, sharing of those best practices, compliance audit experiences, and growth and
maturity of the markets. As noted above, the objective is to draft a standard that helps ensure that
determinations of available transfer capability are accomplished in a manner that supports the reliable
operation of the Bulk Power System.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
An informal development ad hoc group is presenting a pro forma standard thatThis project will address
the consolidates consolidatation of the existing standards MOD-001-1a, MOD-004-1, MOD-008-1, MOD028-1, MOD-029-1a, and MOD-030-2 into a single standard that covers the reliability-related impact of
Available Transfer Capability (ATC) and Available Flowgate Capability (AFC) calculations, such as the
need for Transmission Service Providers to implement their ATC or AFC calculations in a consistent
manner and share ATC or AFC data with their neighboring Transmission Service Providers or other
entities who need such data for reliability purposes.
The pro forma standard requirements are placed within a new version of MOD-001 (MOD-001-2).
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
Detailed description of this project can be found in the Technical White Paper of thisprovided in the
initial SAR submittal package.

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

2

SAR Information
NERC is working with the North American Energy Standards Board (NAESB) to affect a transfer of the
requirements in currently effective Reliability Standards MOD-001-1, MOD-004-1, MOD-008-1, MOD028-2, MOD-029-1a and MOD-030-2 (i.e., the MOD A Standards) that are not included in proposed
MOD-001-2 to NAESB to be reviewed for possible inclusion in NAESB’s business practice standards.
NERC and the Project 2012-05 ATC Revisions standard drafting team recognize that even if certain
requirements in the existing MOD A Standards do not address reliability issues and, in turn, are not
included in proposed MOD-001-2, those requirements or components within them may be essential for
market or competition purposes and should be transitioned to an organization that focuses on marketbased standards. Given its role in developing commercial business practices for the electricity industry,
NAESB is likely to be the appropriate organization to review the requirements in the currently effective
MOD A Standards that are not included in proposed MOD-001-2. [consider moving this up to objectives
section]

Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization

Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.

Interchange Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

3

Reliability Functions
within a Planning Coordinator area.
Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.

Transmission Service
Provider

Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).

Transmission Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling
Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market Operator

Interface point for reliability functions with commercial functions.

Load-Serving Entity

Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.

Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

4

Reliability and Market Interface Principles
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
Yes
Yes
Yes

Yes

Related Standards
Standard No.

Explanation

MOD-001-1a

Available Transmission System Capability

MOD-004-1

Capacity Benefit Margin

MOD-008-1

Transmission Reliability Margin Calculation Methodology

MOD-028-1

Area Interchange Methodology

MOD-029-1a

Rated System Path Methodology

MOD-030-2

Flowgate Methodology

Related SARs

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

5

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

ERCOT

FERC Order 729 states, in Paragraph 298, “…it is appropriate to exempt entities within ERCOT
from complying with these Reliability Standards. We agree that, due to physical differences of
ERCOT’s transmission system, the MOD Reliability Standards approved herein would not
provide any reliability benefit within ERCOT.”

FRCC

None

MRO

None

NPCC

None

RFC

None

SERC

None

SPP

None

WECC

None

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

6

Project 2012-05 Mapping Document

Transition of MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and
MOD-030-2 to Proposed MOD-001-2
The below mapping document provides information on how the approved requirements within MOD-001-a, MOD-004-1, MOD-008-1,
MOD-028-1, MOD-029-1a, and MOD-030-2 transition into the proposed MOD-001-1. As a general statement, the reliability-based
components of those Reliability Standards are captured in MOD-001-2 while non-reliability-based components will be transition out of the
NERC Reliability Standards. Where a prescriptive existing requirement does not easily map into the proposed MOD-001-2, a description and
change justification is provided.

Requirement in
Approved Standard

MOD-001-1a R1

MOD-001-1a R2
MOD-001-1a R2.1
MOD-001-1a R2.2
MOD-001-1a R2.3

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed Reliability Standard requires disclosure of the method
used to calculate Available Transfer Capability (ATC) but no longer
Requirement R2
requires a registered entity to select a method explicitly described in
the NERC Reliability Standards.
The proposed Reliability Standard will require disclosure of calculation
Requirement R2
frequency but does not specify the range of required calculations.
Requirement R2
See comments on Requirement R2.
Requirement R2
See comments on Requirement R2.
Requirement R2
See comments on Requirement R2.

Requirement in
Approved Standard

MOD-001-1a R3

MOD-001-1a R3.1
MOD-001-1a R3.2
MOD-001-1a R3.2.1
MOD-001-1a R3.2.2
MOD-001-1a R3.3

MOD-001-1a R3.4

MOD-001-1a R3.5
MOD-001-1a R3.6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R2 of the proposed Reliability Standard retains the
obligation to have an Available Transfer Capability Implementation
Requirement R2
Document (ATCID) that reflects its method for calculating Available
Flowgate Capability (AFC) or ATC.
This information would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirements R2 & R5
Requirement R2 and may be addressed under Requirement R5 in
response to a request for clarification.
This rationale would be included within the ATCID created under
Requirement R2
Requirement R2.
This information would be included within the ATCID created under
Requirement R2
Requirement R2.
The identity of the TSPs and Transmission Operators (TOPs) for which it
provides data is captured when a registered entity formally requests
Requirements R5 &R6.
that information under Requirements R5 or R6 of the proposed
Reliability Standard.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.

2

Requirement in
Approved Standard
MOD-001-1a R3.6.1
MOD-001-1a R3.6.2
MOD-001-1a R3.6.3
MOD-001-1a R4
MOD-001-1a R4.1
MOD-001-1a R4.2
MOD-001-1a R4.3
MOD-001-1a R4.4
MOD-001-1a R4.5
MOD-001-1a R4.6
MOD-001-1a R5

MOD-001-1a R6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
The requirement for a Transmission Service Provider (TSP) to notify
registered entities when a change is made to its ATCID is an
administrative burden and provides little to no reliability benefit.
Requirement R5
Posting on its company website or Open Access Same-Time
Information System (OASIS) provides notice that a change has been
made. Although not specifically required under the proposed Reliability
Standards, a registered entity may continue to provide such notice.
Requirement R5 of the proposed Reliability Standard obligates the TSP
Requirement R5 for an ATCID provided upon
to provide its ATCID to any registered entity that needs it for reliability
formal request.
upon request.
Ensuring that ATC, Total Transfer Capability (TTC), Available Flowgate
Capability (AFC), and Total Flowgate Capability (TFC) calculations use
assumptions no more limiting than those used in the planning of
The Requirement has been retired.
operations does not serve a clear reliability goal. The ATCID will have a
description of how ATC, TTC, AFC, or TFC is calculated, with sufficient
detail to allow for a comparison.

3

Requirement in
Approved Standard

MOD-001-1a R7

MOD-001-1a R8
MOD-001-1a R8.1
MOD-001-1a R8.2
MOD-001-1a R8.3
MOD-001-1a R9
MOD-001-1a R9.1
MOD-001-1a R9.1.1
MOD-001-1a R9.1.2
MOD-001-1a R9.1.3
MOD-001-1a R9.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Ensuring that ATC, TTC, AFC, and TFC calculations use assumptions no
more limiting then those used in the planning of operations does not
The Requirement has been retired.
serve a clear reliability goal. The ATCID will have a description of how
ATC, TTC, AFC, or TFC is calculated, with sufficient detail to allow for a
comparison.
The reliability component of ATC is disclosure of a registered entity’s
practice which is still captured, but not the performance aspect of the
The Requirement has been retired.
ATC calculations. Mandating the frequency with which ATC is
calculated does not serve a reliability benefit.
The Requirement has been retired.
See comments on Requirement R8.
The Requirement has been retired.
See comments on Requirement R8.
The Requirement has been retired.
See comments on Requirement R8.
Requirement R6 of the proposed Reliability Standard requires a TOP or
TSP, within 45 calendar days of receiving a written request, to make
available the data or explain why it is not doing so due to
confidentiality, regulatory, or security concerns.
See comments for Requirement R9.
Requirement R5
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.

4

Requirement in
Approved Standard

MOD-004-1 R1
MOD-004-1 R1.1
MOD-004-1 R1.2
MOD-004-1 R1.3
MOD-004-1 R2

MOD-004-1 R3
MOD-004-1 R3.1
MOD-004-1 R3.2
MOD-004-1 R4
MOD-004-1 R4.1
MOD-004-1 R4.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed standard will require registered entities that use Capacity
Benefit Margin (CBM) to have a Capacity Benefit Margin (CBMID) that
Requirement R3
reflects its current practices for determining CBM. The proposed
Reliability Standard does not dictate how CBM must be calculated.
Requirement R3
See comments above.
Requirement R3
See comments above.
Requirement R3
See comments above.
Requirement R5 of the proposed Reliability Standard requires TSPs to
Requirement part R5.2.2
share its CBMID with entities that request it and have a reliability need
for that data.
The applicability of the proposed Reliability Standard has been changed
so that the LSE is not an applicable registered entity within the
Requirement R3
Reliability Standard. The method by which a TSP determines CBM will
be included in its CBMID.
Requirement R3
See comment above.
Requirement R3
See comment above.
The applicability of the proposed Reliability Standard has been changed
so that the Resource Planner (RP) is not an applicable registered entity
The Requirement has been retired.
within the Reliability Standard. The method by which a TSP determines
CBM will be included in its CBMID.
The Requirement has been retired.
See comment above.
The Requirement has been retired.
See comment above.

5

Requirement in
Approved Standard
MOD-004-1 R5
MOD-004-1 R5.1
MOD-004-1 R5.2

MOD-004-1 R6
MOD-004-1 R6.1
MOD-004-1 R6.2

MOD-004-1 R7

MOD-004-1 R8

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed Reliability Standard will require TSPs that use CBM to
Requirement R3
have a CBMID but does not specify what must be included or how it is
calculated.
The proposed standard will require TSPs that use CBM to have a CBMID
Requirement R3
but does not specify what must be included or how it is calculated.
The proposed standard will require TSPs that use CBM to have a CBMID
Requirement R3
but does not specify what must be included or how it is calculated.
The applicability of the proposed standard has been changed so that
the Transmission Planner (TP) is not an applicable registered entity
The Requirement has been retired.
within the standard. The method by which a TSP determines CBM will
be included in its CBMID.
The Requirement has been retired.
See comment above.
The Requirement has been retired.
See comment above.
The proposed standard does not explicitly require that the TSP to notify
Load-Serving Entities (LSEs) and RPs of the amount of CBM set aside.
The SDT determined this requirement provided little to no reliability
The Requirement has been retired.
benefit. The proposed Reliability Standard only requires the TSP to have
a CBMID and make that available to other registered entities, including
LSEs and RPs.
The applicability of the proposed Reliability Standard has been changed
The Requirement has been retired.
so that the TP is not an applicable registered entity within the Reliability
Standard.

6

Requirement in
Approved Standard
MOD-004-1 R9
MOD-004-1 R9.1
MOD-004-1 R9.2
MOD-004-1 R10

MOD-004-1 R11

MOD-004-1 R12

MOD-004-1 R12.1

MOD-004-1 R12.2

MOD-004-1 R12.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The new Requirement R6 requires TSPs to share the data used in CBM
Requirement R6
calculations with registered entities that have a reliability need for that
data. TPs are not longer subject to the Reliability Standard.
Requirement R6
See comment above.
Requirement R6
See comment above.
The applicability of the proposed Reliability Standard has been changed
The Requirement has been retired.
so that the LSE or Balancing Authority (BA) are not applicable registered
entities within the Reliability Standard.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.

7

Requirement in
Approved Standard
MOD-008-1 R1

MOD-008-1 R1.1
MOD-008-1 R1.2
MOD-008-1 R1.3
MOD-008-1 R1.3.1
MOD-008-1 R1.3.2
MOD-008-1 R1.3.3
MOD-008-1 R2

MOD-008-1 R3
MOD-008-1 R4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R4
Requirement R4 requires a TRMID that reflects the TOPs current
practices for determining TRM. The proposed Reliability Standard does
not dictate how TRM must be calculated as such detail provides little to
no reliability benefit.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4 requires a TRMID that describes how TRM values are
determined. Prescribing that the value must come from a predefined
Requirement R4
list of uncertainties or that the value does not double count with CBM
does not provide any reliability benefit.
Requirements R5 and R6 require disclosure of TRMID and underlying
Requirement R5
data upon request if not already posted on OASIS or similar site.
Requirement R4 requires a TRMID that includes the frequency of
Requirement R4
updating; setting an arbitrary date to recalculate TRM does not
contribute to reliability.

8

Requirement in
Approved Standard

MOD-008-1 R5

Requirement in
Approved Standard

MOD-028-1 R1

MOD-028-1 R1.1
MOD-028-1 R1.2
MOD-028-1 R1.3
MOD-028-1 R1.4
MOD-028-1 R1.5
MOD-028-1 R1.5.1
MOD-028-1 R1.5.2
MOD-028-1 R1.5.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R2 and R4, the ATCID and TRMID respectively, would
contain information on how the value is shared and on what frequency.
Requirements R2 & R4
Setting an arbitrary frequency is unnecessary to meet the reliability
goal of disclosure.

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1 requires a TOP to have a written methodology for
determining TTC or TFC. Requirement R2 requires a TSP to have an
Requirements R1 & R2
ATCID that describes how ATC or AFC is determined, which would
include any parts of the TTC/TFC development not covered by a TOP
under Requirement R1.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

9

Requirement in
Approved Standard
MOD-028-1 R1.5.4
MOD-028-1 R2

MOD-028-1 R2.1

MOD-028-1 R2.2

MOD-028-1 R2.3

MOD-028-1 R3

MOD-028-1 R3.1
MOD-028-1 R3.1.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
Requirements R1 & R2
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
Requirements R1 & R2
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice. In addition, R1 requires the TOP to use
Requirements R1 & R2
the defined facility ratings and SOL's, as appropriate, to determine the
TTC value.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1, Part 1.2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

10

Requirement in
Approved Standard
MOD-028-1 R3.1.2
MOD-028-1 R3.1.2
MOD-028-1 R3.2
MOD-028-1 R3.2.1
MOD-028-1 R3.2.2
MOD-028-1 R3.2.2
MOD-028-1 R4
MOD-028-1 R4.1

MOD-028-1 R4.2

MOD-028-1 R4.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 set this obligation upon the TOP and TSP,
Requirements R1 & R2
respectively.
Requirements R1 and R2 require disclosure of practice, which is the
reliability need for this requirement. Verification that a contract is being
Requirements R1 & R2
followed is primarily a commercial issue and not a NERC Reliability
issue.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and Requirement R1
specifically addresses documentation of their process and reliability
points. The remainder of the material in the requirement provides
Requirement R1, Part 1.2
instructions on determining TTC, which is not necessary within a NERC
requirement to protect reliability. The TTC methodology will describe
how these services are used and any necessary clarifications can be
sought under Requirement R5. Having a long list of methods of
incorporating these service did not contribute to reliability.

11

Requirement in
Approved Standard
MOD-028-1 R5

MOD-028-1 R5.1

MOD-028-1 R5.2
MOD-028-1 R5.3
MOD-028-1 R6

MOD-028-1 R6.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
calculation will be discussed within the ATCID and driven by either
Requirements R1 & R2
reliability or market needs, whichever provides for a tighter time frame.
The required periodicity of a TFC or TTC calculation is a method and
region specific issue, and it is not necessary to reliability to specify such
a value.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
Requirement R1 and Parts 1.1 and 1.2.1
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.

12

Requirement in
Approved Standard

MOD-028-1 R6.2

MOD-028-1 R6.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
Requirements R1, Part 1.2.1
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
Requirements R1
calculating TTC does not support a reliability need. The new Reliability
Standard does not prevent "Sum of Facility Ratings" as a limit on the
path, however it does not prescribe it either. "Sum of Facility Ratings"
is a commercial concept; the reliability aspect was addressed in
determining the Incremental Transfer Capability (ITC).

13

Requirement in
Approved Standard

MOD-028-1 R6.4

MOD-028-1 R7

MOD-028-1 R7.1

MOD-028-1 R7.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
Requirements R1
calculating TTC does not support a reliability need. Contractual rights
imply there is already a contract and obligation in place, there is no
reliability benefit in NERC monitoring this contract. The Reliability
Standard does not prevent this from being a limit, but does not
prescribe it either
This requirement serves no direct purpose other than serving as a
Requirement R1
bridge to the requirement parts below.
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
Requirement R1 & R6
requirement addresses. The frequency of disclosure is set by
agreement with the TSP or other factors, and there is no reliability
benefit in setting an arbitrary frequency of providing the value.
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
Requirement R1 & R6
requirement addresses. The frequency of disclosure is set by
agreement with the TSP or other factors, and there is no reliability
benefit in setting an arbitrary frequency of providing the value.

14

Requirement in
Approved Standard

MOD-028-1 R8

MOD-028-1 R9

MOD-028-1 R10

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement is primarily a definition of what Existing Transfer
Commitments (ETC) is and does not provide for system reliability.
Breaking ETC into its component parts is a guide for determining ETC
This Requirement has been retired.
but does not establish a reliability requirement. Under their
agreements with which the transmission commitments are made the
registered entity is obligated to respect those commitments and there
is no need for NERC to monitor this commercial arrangement.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This Requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
Requirements R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This Requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that
Requirements R10 and R11 just provided additional educational
reference to ATC, but did not establish a reliability requirement.

15

Requirement in
Approved Standard

MOD-028-1 R11

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
and the NERC Glossary of Terms defines ATC. Beyond that
This Requirement has been retired.
Requirements R10 and R11 just provided additional educational
reference on what ATC was but did not establish a reliability
requirement.

16

Requirement in
Approved Standard
MOD-029-1a R1

MOD-029-1a R1.1

MOD-029-1a R1.1.1
MOD-029-1a R1.1.1.1
MOD-029-1a R1.1.1.2
MOD-029-1a R1.1.1.3
MOD-029-1a R1.1.2
MOD-029-1a R1.1.3
MOD-029-1a R1.1.4
MOD-029-1a R1.1.5
MOD-029-1a R1.1.6
MOD-029-1a R1.1.7
MOD-029-1a R1.1.8
MOD-029-1a R1.1.9
MOD-029-1a R1.1.10

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirements R1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

17

Requirement in
Approved Standard
MOD-029-1a R1.2
MOD-029-1a R2

MOD-029-1a R2.1

MOD-029-1a R2.1.1

MOD-029-1a R2.1.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Part 1.1 describes the method used to account for
Requirement R1, Part 1.1
Facility Ratings as well as system voltage, transient stability, voltage
stability, and other SOLs.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1, Part 1.2, Requirement R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirement R1 specifically requires the TOP to respect transmission
element ratings, Requirements R1 and R2 requires disclosure of the
TOP and TSP's practices in this regard. The revised Reliability Standard
does not go into detail to require that the starting case for an analysis
Requirement R1, Parts 1.1 & 1.2,
meet these criteria. Requirement R1, Part 1.1 requires that TTC
Requirement R2
accounts for these elements, but does not require that the starting case
meet the criteria described under MOD-029 Requirement R2, Part 2.1.
Trying to list this detail would require a textbook level description of
the process and would not set a reliability goal.
Requirement R1, Parts 1.1 & 1.2,
See comment above.
Requirement R2

18

Requirement in
Approved Standard
MOD-029-1a R2.1.3

MOD-029-1a R2.2

MOD-029-1a R2.3

MOD-029-1a R2.4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Parts 1.1 & 1.2,
See comment above.
Requirement R2
This is not a reliability requirement but a business practice to provide
for some sort of result when a reliability constraint can't be reached.
This requirement part has been retired.
This level of information is appropriate in an instructional context but is
not a reliability requirement. The current Requirement R1 requires the
TOP to describe how it does this, but does not prescribe a method.
As the name implies, there is already an obligation between the parties
to respect a value and Requirement R1 just requires that TTC not
Requirements R1 & R2
exceed reliability limits, it does not rule out a lower limit due to
contractual obligations. There is no reliability benefit to NERC
monitoring to ensure that contractual obligations are met.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
This requirement part has been retired
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.

19

Requirement in
Approved Standard

MOD-029-1a R2.5

MOD-029-1a R2.6

MOD-029-1a R2.7

MOD-029-1a R2.8

MOD-029-1a R3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
This requirement part has been retired.
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
As the name implies, there is already an obligation between the parties
to respect a value and Requirement R1 just requires that TTC not
Requirements R1 & R2
exceed reliability limits, it does not rule out a lower limit due to
contractual obligations. There is no reliability benefit to NERC
monitoring to ensure that contractual obligations are met.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
Requirements R1 & R2
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirements R1 and R2 address this need by requiring a methodology,
Requirements R1 & R2
and in the effort to demonstrate that the methodology was followed
the necessary reports will be developed.
Requirement R1, Part 1.1 requires that SOLs be accounted for in the
Requirements R1 & R2
method used in determining TTC. Requirement R2 requires disclosure
of practices for determining ATC.

20

Requirement in
Approved Standard

MOD-029-1a R4

MOD-029-1a R5

MOD-029-1a R6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
requirement addresses. The frequency of disclosure is set by
agreement with the TSP considering individual facts and circumstances,
Requirements R1, R5, & R6
and there is no reliability benefit in setting an arbitrary frequency of
providing the value. Requirement R6 requires disclosure of data and
Requirement R5 requires disclosure of methods and responding to
requests for clarification.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.

21

Requirement in
Approved Standard

MOD-029-1a R7

MOD-029-1a R8

Requirement in
Approved Standard
MOD-030-2 R1

MOD-030-2 R1.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R7 and R8 do not appear verbatim in the new Reliability
Standard; however, Requirement R2 will require disclosure and the
This requirement has been retired.
NERC Glossary of Terms defines ATC. Beyond that Requirements R7 and
R8 just provided additional educational reference on what ATC was but
did not establish a reliability requirement.
Requirements R7 & R8 do not appear verbatim in the new Reliability
Standard; however, Requirement R2 will require disclosure and the
This requirement has been retired.
NERC Glossary of Terms defines ATC. Beyond that Requirements R7 and
R8 just provided additional educational reference on what ATC was but
did not establish a reliability requirement.
Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This is a summary of the requirement parts and does not in itself
Requirements R1 & R2
establish and obligation.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.

22

Requirement in
Approved Standard
MOD-030-2 R1.2
MOD-030-2 R1.2.1
MOD-030-2 R1.2.2
MOD-030-2 R1.2.3
MOD-030-2 R1.2.4
MOD-030-2 R2
MOD-030-2 R2.1

MOD-030-2 R2.1.1

MOD-030-2 R2.1.1.1
MOD-030-2 R2.1.1.2
MOD-030-2 R2.1.1.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.3 requires each methodology to describe the
process for including any reliability-related constraints requested to be
included by another TOP based on if the requesting TOP includes those
constraints in its TFC or TTC determination. Furthermore, Requirement
R1, Part 1.3.1 states that each TOP that uses the Flowgate methodology
Requirement R1, Parts 1.3 & 1.3.1
shall include in its methodology an impact test process for including
requested constraints. If a generator to Load transfer in a registered
entity’s area or a transfer to a neighboring registered entity impact the
requested constraint by five percent or greater, the requested
constraint shall be included in the TFC determination, otherwise the
requested constraint is not required to be included.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.

23

Requirement in
Approved Standard
MOD-030-2 R2.1.2
MOD-030-2 R2.1.2.1
MOD-030-2 R2.1.2.2
MOD-030-2 R2.1.2.3
MOD-030-2 R2.1.3
MOD-030-2 R2.1.4
MOD-030-2 R2.1.4.1
MOD-030-2 R2.1.4.2
MOD-030-2 R2.2
MOD-030-2 R2.3
MOD-030-2 R2.4

MOD-030-2 R2.5

MOD-030-2 R2.5.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
This requirement part has been retired.
The required periodicity of updating a list is not of a reliability benefit.
This requirement part has been retired.
The required periodicity of updating a list is not of a reliability benefit.
Requirement R1, Part 1.1 requires that SOLs be accounted for in the
Requirement R1, Part 1.1 & Requirement R2 method used in determining TTC. Requirement R2 requires disclosure
of practices for determining ATC.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
Requirements R1 & R2
calculation will be discussed within the ATCID and driven by either
reliability or market needs whichever provides for a tighter time frame.
The frequency of disclosure is set by agreement with the TSP
considering the individual facts and circumstances, and there is no
This requirement part has been retired.
reliability benefit in setting an arbitrary frequency of providing the
value.

24

Requirement in
Approved Standard

MOD-030-2 R2.6
MOD-030-2 R3
MOD-030-2 R3.1
MOD-030-2 R3.2
MOD-030-2 R3.3
MOD-030-2 R3.4
MOD-030-2 R3.5

MOD-030-2 R4

MOD-030-2 R5

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The frequency of disclosure is set by agreement with the TSP
considering the individual facts and circumstances, and there is no
This requirement part has been retired.
reliability benefit in setting an arbitrary frequency of providing the
value.
Requirement R6
Requirement R6 requires data sharing.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirements R1, part 1.1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.

25

Requirement in
Approved Standard

MOD-030-2 R5.1

MOD-030-2 R5.2
MOD-030-2 R5.3

MOD-030-2 R6

MOD-030-2 R6.1
MOD-030-2 R6.1.1
MOD-030-2 R6.1.2
MOD-030-2 R6.2
MOD-030-2 R6.2.1
MOD-030-2 R6.2.2
MOD-030-2 R6.3
MOD-030-2 R6.4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
Requirements R1 & R2
R1. Specifically, Requirement R2, Part 2.2 requires each TSP that uses
the Flowgate Methodology to use the AFC determined by the TSP for
reliability constraints identified in Requirement R1, Part 1.3.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.

26

Requirement in
Approved Standard
MOD-030-2 R6.5
MOD-030-2 R6.6
MOD-030-2 R6.7
MOD-030-2 R7
MOD-030-2 R7.1
MOD-030-2 R7.2
MOD-030-2 R7.3
MOD-030-2 R7.4
MOD-030-2 R7.5
MOD-030-2 R7.6
MOD-030-2 R7.7

MOD-030-2 R8

MOD-030-2 R9

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

27

Requirement in
Approved Standard

MOD-030-2 R10

MOD-030-2 R10.1

MOD-030-2 R10.2

MOD-030-2 R10.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
Requirement R2
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

28

Requirement in
Approved Standard

MOD-030-2 R11

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
Requirement R2
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

New Requirements not found in existing MOD standards
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
N/A
N/A

Project 2012-05 ATC Revisions
October 4, 2013

Description and Change Justification
N/A

29

Proposed Timeline for the
Project 2012-05 Standard Drafting Team (SDT)
Anticipated Date

Location

Event

July 11, 2013

-

SC Authorizes SAR

July 11, 2013

-

Conduct Nominations for Project 2012-05 SDT

July 11, 2013

-

Post SAR for 45-Day Initial Comment Period

August 16, 2013

-

Conduct Initial Ballot

August 26, 2013

-

45-Day Comment Period and Initial Ballot Closes

August 27-30, 2013

Colorado Springs,
Colorado

MOD A Standard Drafting Team Face to Face Meeting to
Respond to Initial Comments and Make Possible Revisions

October 4, 2013

-

Post Standard and Accompanying Materials for 45-day
Comment Period

November 8-18, 2013

-

Conduct Ballot

November 18, 2013

-

45-Day Comment Period and Ballot Closes

November 20-22, 2013

TBD

MOD A Standard Drafting Team Face to Face Meeting to
Respond to Ballot Period Comments

December 2-12, 2013

-

Conduct Final Ballot

December 2013

-

NERC Board of Trustees Adoption

December 31, 2013

-

NERC Files Petition with the Applicable Governmental
Authorities

DRAFT Reliability Standard Audit Worksheet1
MOD-001-2 – Modeling, Data, and Analysis – Available Transmission System
Capability
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s)2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
Audit
Supplied by CEA

Applicability of Requirements [RSAW developer to insert correct applicability]
BA
R1
R2
R3
R4
R5
R6

DP

GO

GOP

IA

LSE

PA

PSE

RC

RP

RSG

TO

TOP
3
X

TP

TSP
3

X
3
X
3

X
3
X
3
X

3

X
3
X

1

NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered
entity’s compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW
should choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the
methodology that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a
substitute for the Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language
contained in the Reliability Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability
Standards can be found on NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the
same frequency. Therefore, it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability
Standard. It is the responsibility of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable
governmental authority, relevant to its registration status.
The NERC RSAW language contained within this document provides a non-exclusive list, for informational purposes only, of examples of the types of evidence a
registered entity may produce or may be asked to produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples
contained within this RSAW does not necessarily constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW
reserves the right to request additional evidence from the registered entity that is not included in this RSAW. Additionally, this RSAW includes excerpts from FERC
Orders and other regulatory references. The FERC Order cites are provided for ease of reference only, and this document does not necessarily include all applicable
Order provisions. In the event of a discrepancy between FERC Orders, and the language included in this document, FERC Orders shall prevail.
2
3

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.
Functional Entities operating within the Electric Reliability Council of Texas (ERCOT) are exempt from MOD-001-2.

Subject Matter Experts
Identify Subject Matter Expert(s) responsible for this Reliability Standard. (Insert additional rows if necessary)
Registered Entity Response (Required):
SME Name
Title

Organization

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

2

Requirement(s)

R1 Supporting Evidence and Documentation
R1.

Each Transmission Operator that determines Total Flowgate Capability (TFC) or Total Transfer
Capability (TTC) shall develop a written methodology (or methodologies) for determining TFC or TTC
values. The methodology (or methodologies) shall reflect the Transmission Operator’s current
practices for determining TFC or TTC values.
1.1 Each methodology shall describe the method used to account for the following limitations in
both the pre- and post-contingency state:
1.1.1

Facility ratings;

1.1.2

System voltage limits;

1.1.3

Transient stability limits;

1.1.4

Voltage stability limits; and

1.1.5

Other System Operating Limits (SOLs).

1.2 Each methodology shall describe the method used to account for each of the following
elements, provided such elements impact the determination of TFC or TTC:
1.2.1

The simulation of transfers performed through the adjustment of generation, Load, or
both;

1.2.2

Transmission topology, including, but not limited to, additions and retirements;

1.2.3

Expected transmission uses;

1.2.4

Planned outages;

1.2.5

Parallel path (loop flow) adjustments;

1.2.6

Load forecast; and

1.2.7

Generator dispatch, including, but not limited to, additions and retirements.

1.3 Each methodology shall describe the process for including any reliability-related constraints that
are requested to be included by another Transmission Operator, provided that (1) the request
references this specific requirement, and (2) the requesting Transmission Operator includes
those constraints in its TFC or TTC determination.
1.3.1 Each Transmission Operator that uses the Flowgate Methodology shall include in its
methodology an impact test process for including requested constraints. If a generator to
Load transfer in a registered entity’s area or a transfer to a neighboring registered entity
impact the requested constraint by five percent or greater, the requested constraint shall
be included in the TFC determination, otherwise the requested constraint is not required
to be included.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

3

1.3.2 Each Transmission Operator that uses the Area Interchange or Rated System Path
Methodology shall describe the process it uses to account for requested constraints that
have a five percent or greater distribution factor for a transfer between areas in the TTC
determination; otherwise the requested constraint is not required to be included. When
testing transfers involving the requesting Transmission Operators area, the requested
constraint may be excluded.
1.3.3 A different method for determining whether requested constraints need to be included
in the TFC or TTC determination may be used if agreed to by the Transmission Operators.
M1. Each Transmission Operator that determines TFC or TTC shall provide its current methodology (or
methodologies) or other evidence (such as written documentation) to show that its methodology (or
methodologies) contains the following:
A description of the method used to account for the limits specified in part 1.1. Methods of
accounting for these limits may include, but are not limited to, one or more of the following:
o TFC or TTC being determined by one or more limits.
o Simulation being used to find the maximum TFC or TTC that remains within the limit.
o The application of a distribution factor in determining if a limit affects the TFC or TTC value.
o Monitoring a subset of limits and a statement that those limits are expected to produce the
most severe results.
o A statement that the monitoring of a select limit(s) results in the TFC or TTC not exceeding
another set of limits.
o A statement that one or more of those limits are not applicable to the TFC or TTC
determination.
A description of the method used to account for the elements specified in part 1.2, provided such
elements impact the determination of TFC or TTC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:
o A statement that the element is not accounted for since it does not affect the determination
of TFC or TTC.
o A description of how the element is used in the determination of TFC or TTC.
(1.3) A copy of the request and a description of the method used to perform the impact test
(1.3.1) or account for the requested constraints (1.3.2).
The Transmission Operator shall also be using their current method to determine TFC or TTC.
Evidence of this could be, but is not limited to, a demonstration that a selection of currently
active TFC or TTC values were calculated based on the current methodology.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

4

Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested4:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M1 for evidence to demonstrate compliance.
See notes to auditor section when the TOP does not determine TFC or TTC values.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R1
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Review the methodology (or methodologies or other evidence per M1) and determine whether it
addresses all the sub-requirements of Requirement R1.
Note to Auditor: With regard to “current” practices, the auditor may at their discretion ask for a live
demonstration during the audit of currently determined values, or may ask for written evidence that
demonstrates the values were calculated based on the current practice, or both.
4

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
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Although a registered entity may meet the registration criteria to be registered as a Transmission Operator,
there are instances where that Transmission Operator does not determine TFC or TTC values. In these
instances, as the registered entity does not determine these values, it would therefore not be required to
fulfill the requirements.
An auditor will first come to an understanding of how the entity operates and whether they determine TFC or
TTC. In the event that it is clear to the auditor that the entity does not determine TFC or TTC, this will be
sufficient evidence for the auditor that the appropriate requirements are not applicable to that entity. If
questions remain after this verification, the auditor could look to neighboring entities for confirmation.

Auditor Notes:

R2 Supporting Evidence and Documentation
R2.

Each Transmission Service Provider that determines Available Flowgate Capability (AFC) or Available
Transfer Capability (ATC) shall develop an Available Transfer Capability Implementation Document
(ATCID) that describes the methodology (or methodologies) it uses to determine AFC or ATC values.
The methodology (or methodologies) shall reflect the Transmission Service Provider’s current
practices for determining AFC or ATC values. Each methodology shall describe the method used to
account for the following elements that impact the determination of AFC or ATC:
2.1. Each methodology shall describe the method used to account for the following elements that
impact the determination of AFC or ATC:
2.1.1.

The simulation of transfers performed through the adjustment of generation, Load, or
both;

2.1.2.

Transmission topology, including, but not limited to, additions and retirements;

2.1.3.

Expected transmission uses;

2.1.4.

Planned outages;

2.1.5.

Parallel path (loop flow) adjustments;

2.1.6.

Load forecast; and

2.1.7.

Generator dispatch, including, but not limited to, additions and retirements.

2.2. Each Transmission Service Provider that uses the Flowgate Methodology shall, for reliability
constraints identified in part 1.3, use the AFC determined by the Transmission Service Provider
for that constraint.
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M2. Each Transmission Service Provider that determines AFC or ATC shall provide its current ATCID or
other evidence (such as written documentation) to show that its ATCID contains the following:
A description of the method used to account for the elements specified in part 2.1, provided such
elements impact the determination of AFC or ATC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:
o A description of how the element is used in the determination of AFC or ATC.
o A statement that the element is not accounted for since it does not affect the determination
of AFC or ATC.
o A statement that the element is accounted for in the determination of TFC or TTC by the
Transmission Operator, and does not otherwise affect the determination of AFC or ATC.
Each Transmission Service Provider that uses the Flowgate Methodology shall provide a
description of the method in which AFC provided by another Transmission Service Provider was
used for the reliability constraints identified in part 1.3.
The Transmission Service Provider shall also be using their current method to determine AFC or
ATC. Evidence of this could be, but is not limited to, a demonstration that a selection of currently
active AFC or ATC values were calculated based on the current methodology.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested5:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M2 for evidence to demonstrate compliance.
See notes to auditor section when the TSP does not determine AFC or ATC values.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
5

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
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7

Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R2
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Review the methodology (or methodologies or other evidence per M2) and determine whether it
addresses all the sub-requirements of Requirement R2.
Note to Auditor: With regard to “current” practices, the auditor may at their discretion ask for a live
demonstration during the audit of currently determined values, or may ask for written evidence that
demonstrates the values were calculated based on the current practice, or both.
Although a registered entity may meet the registration criteria to be registered as a Transmission Service
Provider, there are instances where that Transmission Service Provider does not determine AFC or ATC. In
these instances, as the registered entity does not determine these values, it would therefore not be required
to fulfill the requirements.
An auditor will first come to an understanding of how the entity operates and whether they determine AFC or
ATC. In the event that it is clear to the auditor that the entity does not determine AFC or ATC, this will be
sufficient evidence for the auditor that the appropriate requirements are not applicable to that entity. If
questions remain after this verification, the auditor could look to neighboring entities for confirmation.

Auditor Notes:

R3 Supporting Evidence and Documentation
R3.

Each Transmission Service Provider that determines Capacity Benefit Margin (CBM) values shall
develop a Capacity Benefit Margin Implementation Document (CBMID) that describes its method for
establishing CBM. The method described in the CBMID shall reflect the Transmission Service
Provider’s current practices for determining CBM values.

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M3. Each Transmission Service Provider that determines CBM shall provide evidence, including, but not
limited to, its current CBMID, current CBM values, or other evidence (such as written documentation,
study reports, or supporting information) to demonstrate that it established CBM values consistent
with its methodology described in the CBMID. If a Transmission Service Provider does not maintain
CBM, examples of evidence include, but are not limited to, an affidavit, statement, or other
documentation that states the Transmission Service Provider does not maintain CBM.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested6:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M3 for evidence to demonstrate compliance.
See notes to auditor section when the TSP does not determine CBM values.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

6

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
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Compliance Assessment Approach Specific to MOD-001-2, R3
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Review evidence and determine whether it describes the entity’s current method for establishing CBM.
Note to Auditor: In cases where a registered entity asserts it does not determine CBM, this requirement is not
applicable. An auditor could use his or her knowledge of the entity and the BES in its area, obtained through
general knowledge or research conducted prior to the audit, to assess the reasonableness of this claim. An
auditor could also obtain an attestation that the registered entity does not determine CBM and may further
look into the registered entity’s ATC equations for previously determined values to see that CBM was not
determined.
This approach to compliance assessment is supported in FERC Order 729 at P 298, FERC stated, “though MOD004-1 [CBM] is not as explicit with regard to its applicability, we believe that its applicability is implicitly
reserved to those entities that maintain capacity benefit margin. Thus, it does not appear that Entergy, or any
other entity, would be in violation of MOD-004-1 [CBM] or MOD-008-1 [TRM] if it does not maintain
transmission reliability margin or capacity benefit margin.”

Auditor Notes:

R4 Supporting Evidence and Documentation
R4. Each Transmission Operator that determines Transmission Reliability Margin (TRM) values shall
develop a Transmission Reliability Margin Implementation Document (TRMID) that describes its
method for establishing TRM. The method described in the TRMID shall reflect the Transmission
Operator’s current practices for determining TRM values.
M4. Each Transmission Operator that determines TRM shall provide evidence including, but not limited
to, its current TRMID, current TRM values, or other evidence (such as written documentation,
study reports, or supporting information) to demonstrate that it established TRM values
consistent with its methodology described in the TRMID. If a Transmission Operator does not
maintain TRM, examples of evidence include, but are not limited to, an affidavit, statement, or
other documentation that states the Transmission Operator does not maintain TRM.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.
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Evidence Requested7:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M4 for evidence to demonstrate compliance.
See notes to auditor section when the TOP does not determine TRM values.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R4
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Review evidence and determine whether it describes the entity’s current method for establishing TRM.
Note to Auditor: In cases where a registered entity asserts it does not determine TRM, this requirement is not
applicable. An auditor could use his or her knowledge of the entity and the BES in its area, obtained through
general knowledge or research conducted prior to the audit, to assess the reasonableness of this claim. An
auditor could also obtain an attestation that the registered entity does not determine TRM, and may further
investigate the registered entity’s ATC equations for previously determined values to see that TRM was not
determined. If the Transmission Operator is not a Transmission Service Provider, then the Transmission
Service Provider that uses the Transmission Operator’s TFC or TTC Values (if there is one) can be contacted (at
the auditor’s discretion) to confirm they do not use a TRM provided by the Transmission Operator.
7

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
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11

This approach to compliance assessment is supported in FERC Order 729 at P 298, FERC stated, “though MOD004-1 [CBM] is not as explicit with regard to its applicability, we believe that its applicability is implicitly
reserved to those entities that maintain capacity benefit margin. Thus, it does not appear that Entergy, or any
other entity, would be in violation of MOD-004-1 [CBM] or MOD-008-1 [TRM] if it does not maintain
transmission reliability margin or capacity benefit margin.”
Auditor Notes:

R5 Supporting Evidence and Documentation
R5. Within 45 calendar days of receiving a written request that references this specific requirement
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission
Planner, Transmission Service Provider, or any other registered entity that demonstrates a
reliability need, each Transmission Operator or Transmission Service Provider shall provide:
5.1.

A written response to any request for clarification of its TFC or TTC methodology, ATCID,
CBMID, or TRMID. If the request for clarification is contrary to the Transmission Operator’s
or Transmission Service Provider’s confidentiality, regulatory, or security requirements
then a written response shall be provided explaining the clarifications not provided, on
what basis and whether there are any options for resolving any of the confidentiality,
regulatory, or security concerns.

5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s
effective:
5.2.1 TRMID; and
5.2.2 TFC or TTC methodology.

5.3.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s
effective:
5.3.1 ATCID; and
5.3.2 CBMID.

M5. Examples of evidence include, but are not limited to:
Dated records of the request and the Transmission Operator’s or Transmission Service
Provider’s response to the request;
A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests; or

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A statement by the Transmission Operator or Transmission Service Provider that they do not
determine one or more of these values: AFC, ATC, CBM, TFC, TTC or TRM.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested8:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M5 for evidence to demonstrate compliance.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R5
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Through either discussions with the entity under audit or other Planning Coordinators, Reliability
8

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
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Coordinators, Transmission Operators, Transmission Planners, Transmission Service Providers, or any
combination thereof, determine if a request was made in accordance with parts 5.1 through 5.3. If such a
request was made, then determine that the entity under audit responded in accordance with parts 5.1
through 5.3 within 45 calendar days from receipt of the request.
Note to Auditor: In general, evidence obtained from independent third parties is stronger than assertions
from the entity under audit. However, based upon the auditor’s perception of the risk of this requirement to
the BES and the entity’s management practices (or internal controls) a simple assertion may provide sufficient
evidence of compliance in many cases.
The aforementioned 45 day time period begins on the day when the written request was received by the
entity. Dated emails would constitute one example of appropriate evidence of receipt and response under this
requirement.
Auditor Notes:

R6 Supporting Evidence and Documentation
R6. Each Transmission Operator or Transmission Service Provider that receives a written request from
another Transmission Operator or Transmission Service Provider for data related to AFC, ATC, TFC,
or TTC determinations that (1) references this specific requirement, and (2) specifies that the
requested data is for use in the requesting party’s AFC, ATC, TFC, or TTC determination shall take
one of the actions below. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
6.1. In responding to a written request for data on an ongoing basis, the Transmission Service
Provider or Transmission Operator shall make available its data on an ongoing basis no later
than 45 days from receipt of the written request. Unless otherwise agreed upon, the
Transmission Operator or Transmission Service Provider is not required to:
6.1.1 Alter the format in which it maintains or uses the data; or
6.1.2 Make available the requested data on a more frequent basis than it produces the
data and in no event shall it be required to provide the data more frequently than
once an hour.
6.2 In responding to all other data requests, each Transmission Operator or Transmission Service
Provider shall make available the requested data within 45 days of receipt of the written
request. Unless otherwise agreed upon, the Transmission Operator or Transmission Service
Provider is not required to alter the format in which it maintains or uses the data.
6.3 If making available any requested data under parts 6.1 or 6.2 of this requirement is contrary
to the Transmission Operator’s or Transmission Service Provider’s confidentiality, regulatory,
or security requirements, the Transmission Operator or Transmission Service Provider shall
not be required to make available that data; provided that, within 45 days of the written
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request, it responds to the requesting registered entity specifying the data that is not being
provided, on what basis and whether there are any options for resolving any of the
confidentiality, regulatory or security concerns.
M6. Examples of evidence for a data request that involves providing data at regular intervals on an
ongoing basis (6.1), include, but are not limited to:
Dated records of a registered entity’s request, and examples of the response being met;
Dated records of a registered entity’s request, a statement from the requestor that the
request was met (demonstration that the response was met is not required if the requestor
confirms it is being provided); or
A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.
Examples of evidence for all other data requests (6.2) include, but are not limited to:
Dated records of a registered entity’s request, and the response to the request;
Dated records of a registered entity’s request, a statement from the requestor that the
request was met; or
A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.
An example of evidence of a response by the Transmission Operator or Transmission Service
Provider that providing the data would be contrary to the registered entity’s confidentiality,
regulatory, or security requirements (6.3) includes a response to the requestor specifying the data
that is not being provided, on what basis and whether there are any options for resolving any of
the confidentiality, regulatory, or security concerns.

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Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested9:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M6 for evidence to demonstrate compliance.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R6
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Through either discussions with the entity under audit or other Transmission Service Providers,
Transmission Operators, or any combination thereof, determine if a request was made in accordance with
Requirement R6. If such a request was made, then determine that the entity under audit responded in
accordance with parts 6.1 through 6.3 within 45 calendar days from receipt of the request.
Note to Auditor: In general, evidence obtained from independent third parties is stronger than assertions
from the entity under audit. However, based upon the auditor’s perception of the risk of this requirement to
the BES and the entity’s management practices (or internal controls) a simple assertion may provide sufficient
evidence of compliance in many cases.
The aforementioned 45 day time period begins on the day when the written request was received by the
entity. Dated emails would constitute one example of appropriate evidence of receipt and response under this
requirement.
9

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.

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Auditor Notes:

Revision History
Version
1

Date
10/31/2013

Reviewers
NERC Compliance,
Standards

Revision Description
New Document

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17

Project 2012-05 - ATC Revisions (MOD A)
Consideration of Directives (November 12, 2013)
Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10204 – Order No. 729 at P 129
129. If the Commission determines upon its own review of the data,
or upon review of a complaint, that it should investigate the
implementation of the available transfer capability methodologies,
the Commission will need access to historical data. Accordingly,
pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, the Commission directs the ERO to modify the Reliability
Standards so as to increase the document retention requirements to a
term of five years, in order to be consistent with the enforcement
provisions established in Order No. 670.

1

(2000)).

Consideration of Directive
Consistent with FERC’s directive, proposed MOD-001-2 requires
applicable registered entities to retain the implementation and
methodology documents required under Requirements R1-R4 for
five years. For the components of the calculations and the results of
such calculations for all values contained in the implementation
and methodology documents, the proposed standard provides a
graduated time frame for the calculations of hourly, daily, and
monthly values. Evidence of hourly values must be retained for 14
days, daily values for 30 days and monthly values for 60 days. The
standard drafting team (“SDT”) concludes there is little to no
benefit of requiring entities to retain such detailed supporting data
of the calculations for longer periods. The SDT notes that to comply
with Commission requirements under Order No. 670,1 however,
entities may be required to retain such supporting data for longer
periods.

Prohibition of Energy Market Manipulation, Order No. 670, 71 FR 4244 (Jan. 26, 2006), FERC Stats. & Regs. ¶ 31,202, at PP 62- 63 (2006) (citing 28 U.S.C. § 2462

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10206 – Order No. 729 at P 151
151. Nevertheless, the Commission believes that the lists of required
recipients of the implementation documents may be overly
prescriptive and could exclude some registered entities with a
reliability need to review such information. Accordingly, pursuant to
section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop a modification to the
Reliability Standards pursuant to the ERO’s Reliability Standards
development process to require disclosure of the various
implementation documents to any registered entity who
demonstrates to the ERO a reliability need for such information.

VRF and VSL Justifications

Consideration of Directive
Consistent with the Commission’s directive, Requirement R5 of the
proposed standard requires that the implementation documents be
made available to any registered entity that demonstrates a
reliability need for such information, subject to confidentiality,
regulatory, and security requirements.

2

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10207 – Order No. 729 at P 160
160. In Order No. 890, the Commission also expressed concern
regarding the treatment of reservations with the same point of receipt
(generator), but multiple points of delivery (Load), in setting aside
existing transmission capacity. The Commission found that such
reservations should not be modeled in the existing transmission
commitments calculation simultaneously if their combined reserved
transmission capacity exceeds the generator’s nameplate capacity at
the point of receipt. The Commission required the development of
Reliability Standards that lay out clear instructions on how these
reservations should be accounted for by the transmission service
provider. The proposed Reliability Standards achieve this by requiring
transmission service providers to identify in their implementation
documents how they have implemented MOD-028-1, MOD-029-1, or
MOD-030-2, including the calculation of existing transmission
commitments. Thus we will not direct the ERO to develop a
modification to address over-generation, as suggested by Entegra.
Nonetheless, in developing the modifications to the MOD Reliability
Standards directed in this Final Rule, the ERO should consider
generator nameplate ratings and transmission line ratings including
the comments raised by Entegra and ISO/RTO Council.

2

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed reliability standard. First, in a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.2 Additionally, the SDT concludes that the comments
regarding generator nameplate ratings and transmission line
ratings do not relate to the reliability issues associated with
Available Flowgate Capability (AFC) and Available Transfer
Capability (ATC) calculations. The SDT notes that the comments
relate to the determination of existing transmission commitments
(ETC), which is a component of ATC or AFC that would be disclosed
in an entity’s Available Transfer Capability Implementation
Document (ATCID) under Requirement R2 of the proposed
standard. Specifying the manner in which ETC is determined, which
would include generator nameplate ratings and transmission line
ratings, where appropriate, is not necessary for reliability purposes.
NERC is working with the North American Energy Standards Board
(NAESB) to transfer those elements from the MOD A standards that
relate to commercial or business practices and are not included in
proposed MOD-001-2 into NAESB’s business practice standards.
When considering whether to incorporate those elements into its
business practice standards, NAESB could consider whether it is
appropriate to address this directive.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

3

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10208 – Order No. 729 at P 162
162. In Order No. 890, the Commission directed public utilities,
working through NERC, to modify MOD-010 through MOD-025 to
incorporate a periodic review and modification of various data
models. The Commission found that updating and benchmarking was
essential to accurately simulate the performance of the transmission
grid and to calculate comparable available transfer capability values.
On rehearing, the Commission clarified that the models used by the
transmission provider to calculate available transfer capability, and
not actual available transfer capability values, must be benchmarked.
Updating and benchmarking of models to actual events will ensure
greater accuracy, which will benefit information provided to and used
by adjacent transmission service providers who rely upon such
information to plan their systems. Accordingly, pursuant to section
215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop benchmarking and updating
requirements to measure modeled available transfer and flowgate
capabilities against actual values. Such requirements should specify
the frequency for benchmarking and updating the available transfer
and flowgate capability values and should require transmission service
providers to update their models after any incident that substantially
alters system conditions, such as generation outages.

VRF and VSL Justifications

Consideration of Directive
The SDT concludes that the proposed standard is responsive to the
Commission’s concern regarding the accuracy of ATC/AFC values as
system conditions change. Requirements R1 (part 1.2) and R2 (part
2.1) of the proposed standard require that a Transmission
Operator’s (TOP’s) and a Transmission Service Providers (TSP’s)
models for determining Total Flowgate Capability (TFC) or Total
Transfer Capability (TTC) or AFC/ATC, respectively, account for
system topology, including additions and retirements as well as
expected system usage, planned outages, Load forecast and
expected generation dispatch when such elements impact the
determination of TFC, TTC, AFC or ATC. By describing how its
methodology accounts for these elements, adjacent systems will be
able to effectively model their own transfer or flowgate capabilities.
The SDT concludes, however, that because each part of the country
has a different sensitivity to these elements and the frequency with
which they change, there is no additional reliability benefit in
mandating the frequency with which a TOP or TSP must benchmark
or update its models. Under Requirement R6 of the proposed
standard, registered entities are required to share their data with
others, which also increases the amount of up to date information
available for the determination of AFC/ATC values. Additionally,
under Requirements R5 of the proposed standard, a TSP or a TOP
could be asked to clarify its benchmarking or updating practices, if
not already set forth in its documented methodology, and share
data underling those practices. As such, the proposed reliability
addresses the Commission’s directive toward increasing accuracy by
improving transparency.

4

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10209 – Order No. 729 at P 173
173. The Commission therefore directs the ERO, pursuant to section
215(d)(5) of the FPA and section 39.5(f) of our regulations, to develop
a modification to MOD-028-1 and MOD-029-1 to specify that base
generation schedules used in the calculation of available transfer
capability will reflect the modeling of all designated network
resources and other resources that are committed to or have the legal
obligation to run, as they are expected to run, and to address the
effect on available transfer capability of designating and
undesignating a network resource.

NERC S-Ref 10211 – Order No. 729 at P 179
179. We agree that, in order to be useful, hourly, daily and monthly
available transfer capability and available flowgate capability values
must be calculated and posted in advance of the relevant time period.
Requirement R8 of MOD-001-1 and Requirement R10 of MOD-030-2
require that such posting will occur far enough in advance to meet this
need. With respect to Entegra’s request regarding more frequent
updates for constrained facilities, we direct the ERO to consider this
suggestion through its Reliability Standards development process.

3

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. The SDT concludes that this directive
does not relate to the reliability issues associated with ATC or AFC
determinations. Specifically, the directive relates to the inputs for
calculating ETC, which is not relevant to reliability. The SDT
concludes that there is no reliability purpose served by mandating
how generation and network resources should be treated so long
as it is transparent. The SDT notes that under Requirement R2 of
the proposed standard, a TSP should describe its practices related
to the treatment of base generation schedules and the effect of
designating and undesignating a network resource. Under
Requirement R5 of the proposed reliability standard, the TSP will be
required to respond to requests for clarification of its practices on
this issue. The SDT notes that NAESB could consider whether to
address this directive from a commercial perspective.
The SDT determines that it is not necessary to address this directive
in the proposed standard. In a recent Notice of Proposed
Rulemaking, the Commission proposed to withdraw this directive.3
Additionally, the SDT concludes that the frequency of updates for
constrained facilities is not relevant to reliability but relates to
commercial access to the constrained paths. The SDT notes,
however, that an entity’s ATCID should address this issue. NAESB
could consider whether to address this directive from a commercial
perspective.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

5

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10212 – Order No. 729 at P 179
179. Further, we agree with Cottonwood regarding unscheduled or
unanticipated events. Therefore, pursuant to section 215(d)(5) of the
FPA and section 39.5(f) of our regulations, we direct the ERO to
develop modifications to MOD-001-1 and MOD-030-2 to clarify that
material changes in system conditions will trigger an update whenever
practical. Finally, we clarify that these Reliability Standards shall not
be used as a “safe harbor” to avoid other, more stringent reporting or
update requirements.
NERC S-Ref 10214 – Order No. 729 at P 184
184. As proposed, MOD-001-1 does not restrict a transmission service
provider from double-counting data inputs or assumptions in the
calculation of available transfer or flowgate capability. To the extent
possible, available transfer or flowgate capability values should reflect
actual system conditions. The double-counting of various data inputs
and assumptions could cause an understatement of available transfer
or flowgate capability values and, thus, poses a risk to the reliability of
the Bulk-Power System. We note that, in the Commission’s order
accepting the associated NAESB business standards, issued
concurrently with this Final Rule in Docket No. RM05-5-013, the
Commission directs EPSA to address its concerns regarding the
modeling of condition firm service through the NERC Reliability
Standards development process. We reaffirm here that modeling of
available transfer capability should consider the effects of conditional
firm service, including the potential for double-counting. Accordingly,
pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, the Commission directs the ERO to develop modifications
to MOD-001-1 pursuant to the ERO’s Reliability Standards
development process to prevent the double-counting of data inputs
and assumptions. In developing these modifications, the ERO should
consider the effects of conditional firm service.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. The proposed standard is limited to
addressing reliability issues associated with AFC/ATC
determinations. The need to update due to material changes in
system condition is not needed for reliability but serves the
purpose of providing the best information to the market. As such, it
may be appropriate for NAESB to address this issue in its business
practice standards. The SDT notes, however, that an entity’s ATCID
could address this issue.
The SDT concludes that the proposed standard is responsive to the
Commission’s concern. By requiring the documentation and
disclosure of the methodologies for determining TTC/TFC, AFC/ATC,
Capacity Benefit Margin (CBM) and Transmission Reliability Margin
(TRM), registered entities will understand how a neighboring entity
calculates these values and, in turn, reduces the reliability risks
associated with potentially double-counting any data inputs and
assumptions. NAESB may also consider whether the possibility of
double-counting needs to be addressed in greater detail in its
business practice standards.

6

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10215 – Order No. 729 at P 192
192. In its filing letter, NERC states that it requires applicable entities
to calculate available transfer capability or available flowgate
capability on a consistent schedule and for specific time frames. In
keeping with the Commission’s goals of consistency and transparency
in the calculation of available transfer capability or available flowgate
capability, the Commission finds that transmission service providers
should use consistent modeling practices over different time frames. If
a transmission service provider uses inconsistent modeling practices
over different time frames that should be made explicit in its
implementation document along with a justification for the
inconsistent practices. Accordingly, pursuant to section 215(d)(5) of
the FPA and section 39.5(f) of our regulations, the Commission directs
the ERO to develop a modification to the Reliability Standard pursuant
to its Reliability Standards development process requiring
transmission service providers to include in their implementation
documents any inconsistent modeling practices along with a
justification for such inconsistencies.

VRF and VSL Justifications

Consideration of Directive
The SDT concludes that the proposed standard is responsive to the
Commission’s concern. By requiring that TSPs and TOPs document
their methodologies for determining TTC/TFC, AFC/ATC, CBM and
TRM to reflect their current practices, the TSP/TOP must provide
information regarding their modeling practices, including whether
those modeling practices are used consistently. Additionally,
Requirement R5 allows registered entities to request that the
TSP/TOP clarify its methodology, which includes requests about the
TSP’s/TOP’s modeling practices. Should NAESB see a need for
additional detail on modeling practices for purposes of ensuring a
non-discriminatory market, it may further consider this directive.

7

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10216 – Order No. 729 at P 200
200. With regard to Midwest ISO’s concern, while the terms
“assumptions” and “no more limiting” as used in Requirements R6
and R7 could benefit from further granularity, we find these
Requirements to be sufficiently clear for purposes of compliance.
Likewise, with regard to Entegra’s concern, we agree that
transmission service providers should use data and assumptions for
their available transfer capability or available flowgate capability and
total transfer capability or total flowgate capability calculations that
are consistent with those used in the planning of operations and
system expansion. Under Requirements R6 and R7, transmission
service providers and transmission operators must not overstate
assumptions that are used in planning of operations. We believe these
requirements are sufficiently clear as written. Nonetheless, we
encourage the ERO to consider Midwest ISO’s and Entegra’s
comments when developing other modifications to the MOD
Reliability Standards pursuant to the ERO’s Reliability Standards
development procedure.

4

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. In a recent Notice of Proposed
Rulemaking, the Commission proposed to withdraw this directive.4
There is no additional reliability benefit to specifically including a
requirement that the TOP explain how it uses consistent or less
limiting assumptions than their operations planning. This issue may
be considered further by NAESB if it is important for commercial
purposes.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

8

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10217 – Order No. 729 at P 220
220. We agree with NERC that a transmission service provider should
consider any information provided in establishing an appropriate level
of capacity benefit margin. Similarly, we agree with the Georgia
Companies that all relevant information should be considered in
establishing an appropriate level of capacity benefit margin, including
information provided by customers. However, in determining the
appropriate generation capacity import requirement as part of the
sum of capacity benefit margin to be requested from the transmission
service provider, it would not be appropriate for a load-serving entity
or resource planner to rely exclusively on a reserve margin or
adequacy requirement established by an entity that is not subject to
this Standard. Thus, we hereby adopt the NOPR proposal to direct the
ERO to develop a modification to Requirements R3.1 and R.4.1 of
MOD-004-1 to require load-serving entities and resource planners to
determine generation capability import requirements by reference to
one or more relevant studies (loss of load expectation, loss of load
probability or deterministic risk analysis) and applicable reserve
margin or resource adequacy requirements, as relevant. Such a
modification should ensure that a transmission service provider has
adequate information to establish the appropriate level of capacity
benefit margin.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. Under the proposed
standard, the method of calculating CBM is determined by the TSP
and must be described in the TSP’s CBMID. The SDT concludes that
no reliability benefit is provided by placing a requirement on Load
Serving Entities (LSEs) and Resource Planners (RPs) to determine
generation capability import requirements by reference to one or
more relevant studies and applicable reserve margin or resource
adequacy requirements. This issue may be considered further by
NAESB if it is important for commercial purposes.

9

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10218 – Order No. 729 at P 222
222. We agree with the Midwest ISO that ISOs, RTOs, and other
entities with a wide view of system reliability needs should be able to
provide input into determining the total amount of capacity benefit
margin required to preserve the reliability of the system. However,
Requirements R1.3 and R7 already make clear that determinations of
need for generation capability import requirement made by a load
serving entity or resource planner are not final. Further, the third
bullet of Requirements R5 and R6 explicitly lists reserve margin or
resource adequacy requirements established by RTOs and ISOs among
the factors to be considered in establishing capacity benefit margin
values for available transfer capability paths or flowgates used in
available transfer capability or available flowgate capability
calculations. In fact, it is for this reason that we uphold the NOPR
proposal. Therefore, pursuant to section 215(d)(5) of the FPA and
section 39.5(f) of our regulations, the Commission directs the ERO to
modify MOD-004-1 to clarify the term “manage” in Requirement R1.3.
This modification should ensure that the Reliability Standard clarify
how the transmission service provider will manage situations where
the requested use of capacity benefit margin exceeds the capacity
benefit margin available.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. Under the proposed
reliability standard, the method of calculating CBM is determined
by the TSP and must be described in the TSP’s CBMID. The Capacity
Benefit Margin Implementation Document (CBMID) should describe
the manner in which the TSP will manage situations where the
requested use of CBM exceeds the CBM available. The SDT
concludes that no reliability benefit is provided specifically
requiring such a description. This issue may be considered further
by NAESB if it is important for commercial purposes.

10

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10219 – Order No. 729 at P 231
231. The Commission understands sub-requirement R2.2 of MOD-0281 to mean that, when calculating total transfer capability for available
transfer capability paths, a transmission operator shall use a
transmission model that includes relevant data from reliability
coordination areas that are not adjacent. While we believe that the
provision is reasonably clear, the Commission agrees that the term
“and beyond” could be better explained. Accordingly, pursuant to
section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop a modification subrequirement R2.2 pursuant to its Reliability Standards development
process to clarify the phrase “adjacent and beyond Reliability
Coordination areas.”
NERC S-Ref 10220 - Order No. 729 at P 234
234. The Commission believes that, as written, the time frames
established in Requirement R5 are just and reasonable because they
balance the need to reliably operate the grid with the burden on
transmission operators to recalculate total transfer capability even
when total transfer capability does not often change. Nevertheless,
the Commission agrees that a graduated time frame for reposting
could be reasonable in some situations. Accordingly, the ERO should
consider this suggestion when making future modifications to the
Reliability Standards.

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.5 Additionally, the proposed standard does not use the
phrase “adjacent and beyond Reliability Coordination areas.”

The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.6 The SDT considered this issue and concludes that there
is no reliability benefit in requiring specific time frames for an Area
Interchange Methodology user to update their TTC based on an
outage. Under the proposed reliability standard, the time frame
within which a value is recalculated and reposted based on an
outage would be addressed by the TOP in its methodology. This
issue may be considered further by NAESB if it is important for
commercial purposes.

5

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

6

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

11

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10221 – Order No. 729 at P 237
237. The Commission agrees that any distribution factor to be used
should be clearly stated in the implementation document, and that to
facilitate consistent and understandable results the distribution
factors used in determining total transfer capability should be applied
consistently. Accordingly, pursuant to section 215(d)(5) of the FPA
and section 39.5(f) of our regulations, the Commission directs the ERO
to develop a modification to MOD-028-1 pursuant to its Reliability
Standards development process to address these two concerns.

NERC S-Ref 10222 – Order No. 729 at P 246
246. Puget Sound’s request is reasonable, and insofar as calculating
non-firm available transfer capability using counterschedules as
opposed to counterflows achieves substantially equivalent results,
using them will not be considered a violation. However, we do not
have enough information to determine that the terms are generally
interchangeable in all circumstances. The ERO should consider Puget
Sound’s concerns on this issue when making future modifications to
the Reliability Standards.

7

Consideration of Directive
The SDT concludes that the proposed reliability standard is
responsive to the Commission’s concern. First, the proposed
reliability standard requires disclosure of the TOP’s method of
addressing TTC/TFC and the TSP’s method of determining ATC/AFC.
These methods will describe the manner in which TOPs and TSPs
use distribution factors. The description must reflect current
practices. The proposed standard also allows neighboring TOPs to
request that a TOP consider a transmission constraint in its TTC/TFC
determination. Users of the Area Interchange or Rated System Path
Methodology must describe the process they use to account for
requested constraints that have a five percent or greater
distribution factor for a transfer between areas in the TTC
determination.
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.7 Additionally, the SDT concludes that the issue raised by
Puget Sound is outside the scope of the reliability issues associated
with ATC/AFC determinations.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

12

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10223 – Order No. 729 at P 269
269. As noted above, the Commission approves the proposal to make
these Reliability Standards effective on the first day of the first
calendar quarter that is twelve months beyond the date that the
Reliability Standards are approved by all applicable regulatory
authorities. Although MOD-030-2 defines its effective date with
reference to the effective date of MOD-030-1, the Commission finds
that this direction is sufficiently clear in the context of the current
proceeding. To the extent necessary, we clarify MOD-030-2 shall
become effective on the first day of the first calendar quarter that is
twelve months beyond the date that the Reliability Standards are
approved by all applicable regulatory authorities. The Commission
also directs the ERO to make explicit such detail in any future version
of this or any other Reliability Standard.
NERC S-Ref 10226 – Order No. 729 at P 304
304. The Commission believes that the definition of Postback is not
fully determinative. NERC should be able to define this term without
reference to the Business Practices, another defined term.
Accordingly, the Commission adopts its NOPR proposal and directs the
ERO to develop a modification to the definition of Postback to
eliminate the reference to Business Practices. Although we are
sensitive to Puget Sound’s concern that the required Postback
component may increase the recordkeeping burden on some entities,
in other regions the component may be critical. We disagree that the
term’s existence assumes that once a reservation is confirmed on a
particular point of reservation or point of receipt combination the
impact of the confirmed reservation will always be present in the
available transfer capability calculation. However, we would consider
suggestions that would allow entities to comply with the
requirements as efficiently as possible, such as a regional difference
through the ERO’s standards development procedure.

8

Consideration of Directive
The SDT determines that this directive is no longer relevant.
Additionally, in a recent Notice of Proposed Rulemaking, the
Commission proposed to withdraw this directive.8

Because the term “Postback” is not used in the proposed standard,
it is not necessary to address this directive. The term “Postback” is
not used in any other standard. Any necessary revisions to NERC’s
Glossary of Terms to remove the term “Postback” will be addressed
in a subsequent project modifying the NERC Glossary.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

13

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10227 – Order No. 729 at P 305
305. The Commission also adopts its NOPR proposal to direct the ERO
to develop a modification to the definition of Business Practices that
would remove the reference to regional reliability organizations and
replace it with the term Regional Entity. We also direct the ERO to
develop a definition of the term Regional Entity to be included in the
NERC Glossary.
NERC S-Ref 10229 – Order No. 729 at P 306
306. We agree with SMUD and Salt River that the definition of “ATC
Path” should not limit a transmission provider’s flexibility to treat
multiple parallel interconnections between balancing authorities as a
single path, and that available transfer capability paths may comprise
multiple, parallel interconnections between Balancing Authorities
when such treatment is appropriate to maintain reliability. We also
agree that the definition should not reference the Commission’s
regulations. The Commission’s regulations are not applicable to all
registered entities and are subject to change. We therefore direct the
ERO to develop a modification to the definition of “ATC Path” that
does not reference the Commission’s regulations.

VRF and VSL Justifications

Consideration of Directive
Because the term “Business Practices” is not used in the proposed
standard, it is not necessary to address this directive. Any
necessary revisions to NERC’s Glossary of Terms related to the term
“Business Practices” will be part of any subsequent project
modifying the NERC Glossary

Because the term “ATC Path” is not used in the proposed standard,
it is not necessary to address this directive. The term “ATC Path” is
not used in any other standard. Any necessary revisions to NERC’s
Glossary of Terms to remove the term “ATC Path” will be part of
any subsequent project modifying the NERC Glossary.

14

Standards Announcement Reminder
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2

Additional Ballot and Non-Binding Poll now open through November 18, 2013
Now Available

An additional ballot for MOD-001-2 and non-binding poll of the associated Violation Risk Factors
(VRFs) and Violation Severity Levels (VSLs) is open through 8 p.m. Eastern on Monday, November
18, 2013.
Background information for this project can be found on the project page.
Instructions for Balloting

Members of the ballot pools associated with this project may log in and submit their vote for the
standard and non-binding poll of the associated VRFs and VSLs by clicking here.
Next Steps

The ballot results for MOD-001-2 will be announced and posted on the project page. The drafting
team will consider all comments received during the formal comment period and, if needed, make
revisions to the standard. If the comments do not show the need for significant revisions, the
standard will proceed to a final ballot.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Comment Period: October 4, 2013 – November 18, 2013
Upcoming:
Additional Ballot and Non-Binding Poll: November 8, 2013 - November 18, 2013
Now Available

A 45-day formal comment period for MOD-001-2 is open through 8 p.m. Eastern on Monday,
November 18, 2013.
Background information for this project can be found on the project page.
Instructions for Commenting

A formal comment period is open through 8 p.m. Eastern on Monday, November 18, 2013. Please
use the electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Wendy Muller. An off-line, unofficial copy of the comment form is
posted on the project page.
Next Steps

An additional ballot for MOD-001-2 and non-binding poll of the associated Violation Risk Factors
and Violation Severity Levels will be conducted as outlined above.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Comment Period: October 4, 2013 – November 18, 2013
Upcoming:
Additional Ballot and Non-Binding Poll: November 8, 2013 - November 18, 2013
Now Available

A 45-day formal comment period for MOD-001-2 is open through 8 p.m. Eastern on Monday,
November 18, 2013.
Background information for this project can be found on the project page.
Instructions for Commenting

A formal comment period is open through 8 p.m. Eastern on Monday, November 18, 2013. Please
use the electronic form to submit comments. If you experience any difficulties in using the
electronic form, please contact Wendy Muller. An off-line, unofficial copy of the comment form is
posted on the project page.
Next Steps

An additional ballot for MOD-001-2 and non-binding poll of the associated Violation Risk Factors
and Violation Severity Levels will be conducted as outlined above.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Additional Ballot and Non-Binding Poll Results
Now Available

An additional ballot for MOD-001-2 and non-binding poll of the associated Violation Risk Factors
and Violation Severity Levels concluded at 8 p.m. Eastern on Wednesday, November 20, 2013.
The standard achieved a quorum and received sufficient affirmative votes for approval. Voting
statistics are listed below, and the Ballot Results page provides a link to the detailed results for the
ballot.
Approval
Quorum: 81.69%
Approval: 82.97%

Non-Binding Poll Results
Quorum: 80.91%
Supportive Opinions: 79.11%

Background information for this project can be found on the project page.
Next Steps

The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the standard. If the comments do not show the need for significant
revisions, the standard will proceed to a final ballot.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

NERC Standards

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Ballot Name: Project 2012-05 ATC Revisions MOD A (MOD-001-2)

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Ballot Period: 11/8/2013 - 11/20/2013
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Total # Votes: 299

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Total Ballot Pool: 366
Quorum: 81.69 %  The Quorum has been reached
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82.97 %
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Ballot Results: The Standard has passed.

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Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote

1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals

1
2
3
4
5
6
7
8
9

105

1

60

0.8

15

0.2

1

11

18

10

0.7

6

0.6

1

0.1

0

1

2

78

1

48

0.828

10

0.172

0

9

11

28

1

14

0.824

3

0.176

0

5

6

81

1

41

0.759

13

0.241

0

8

19

51

1

25

0.714

10

0.286

0

6

10

0

0

0

0

0

0

0

0

0

4

0.3

3

0.3

0

0

0

0

1

2

0.2

2

0.2

0

0

0

0

0

7

0.7

7

0.7

0

0

0

0

0

366

6.9

206

5.725

52

1.175

1

40

67

Individual Ballot Pool Results

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

NERC Standards

Segment

1
1

Organization

Member

Ameren Services

Vijay Sankar
Eric Scott

1

American Electric Power

Paul B Johnson

1

American Transmission Company, LLC

Andrew Z Pusztai

1

Arizona Public Service Co.

Robert Smith

1
1
1
1
1
1
1
1

Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Bonneville Power Administration

John Bussman
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Donald S. Watkins

Ballot

Negative

Negative

Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative

1
1
1
1

John C Fontenot
John Brockhan
Michael B Bax
Joseph Turano Jr.

Affirmative
Abstain
Affirmative
Affirmative

Chang G Choi

Affirmative

1
1
1
1

Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities

Affirmative
Affirmative

1

Consolidated Edison Co. of New York

1
1
1
1
1
1
1
1
1

CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.

Daniel S Langston
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de
Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Pablo Onate
Oliver A Burke
William J Smith

1

Florida Keys Electric Cooperative Assoc.

Dennis Minton

1

Florida Power & Light Co.

Mike O'Neil

Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Affirmative

1

Gainesville Regional Utilities

Richard Bachmeier

1

Georgia Transmission Corporation

Jason Snodgrass

1

Great River Energy

Gordon Pietsch

Negative

1
1
1

Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
JEA

Ajay Garg
Martin Boisvert
Molly Devine

Affirmative
Affirmative

Michael Moltane

Affirmative

Jim D Cyrulewski
Ted Hobson

Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

COMMENT
RECEIVED

Affirmative

Tony Kroskey

1
1

SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz
AEP)

Affirmative

Brazos Electric Power Cooperative, Inc.

1

Affirmative

1

1

NERC
Notes

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)

Affirmative
SUPPORTS
THIRD PARTY
COMMENTS (ACES)

NERC Standards
1
1

KAMO Electric Cooperative
Kansas City Power & Light Co.

Walter Kenyon
Jennifer Flandermeyer

1

Lakeland Electric

Larry E Watt

1
1
1
1
1
1
1
1
1
1
1
1
1

Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation

John Chin
Doug Bantam
Robert Ganley
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Daniel L Inman
Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine

New York Power Authority

Bruce Metruck

1
1
1
1
1
1

Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy

Affirmative

Negative

Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

Randy MacDonald
Negative

Kevin White

Affirmative

David Boguslawski
Julaine Dyke
John Canavan

Affirmative
Affirmative
Affirmative

1

Ohio Valley Electric Corp.

Robert Mattey

Negative

1

Oklahoma Gas and Electric Co.

Terri Pyle

Negative

1
1
1
1
1
1

Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
Platte River Power Authority

Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
John C. Collins

1

Portland General Electric Co.

John T Walker

1
1
1

Brenda L Truhe
Laurie Williams
Kenneth D. Brown

1
1
1
1

PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project

1

San Diego Gas & Electric

Will Speer

1
1
1
1

SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.

Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo

1

SUPPORTS
THIRD PARTY
COMMENTS (Flordia
Municipal Power
Agency (FMPA))

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz American
Electric Power)
SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)

Affirmative
Affirmative
Affirmative
Abstain
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (PGE (Angela
Gaines) will be
submitting a
comment
regarding
counterflows.)

Affirmative
Affirmative
Affirmative

Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain

NO COMMENT
RECEIVED

NERC Standards
1
1
1

Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority

Long T Duong
Tom Hanzlik
Shawn T Abrams

Affirmative
Affirmative
Affirmative

1

Southern California Edison Company

Steven Mavis

Negative

1

Southern Company Services, Inc.

Robert A. Schaffeld

1

Southwest Transmission Cooperative, Inc.

John Shaver

Negative

1

Sunflower Electric Power Corporation

Noman Lee Williams

Negative

1

Tampa Electric Co.

Beth Young

1

Tennessee Valley Authority

Howell D Scott

1
1
1
1
1
1
1
1

Texas Municipal Power Agency
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

2

BC Hydro

2
2

California ISO
Electric Reliability Council of Texas, Inc.

Brent J Hebert
Steven Powell
Tracy Sliman
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley

2

Independent Electricity System Operator

Barbara Constantinescu

2
2
2
2
2
2

ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.

Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung

Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED

Abstain
Affirmative
Abstain
Affirmative

Affirmative
Affirmative
Abstain
Negative

COMMENT
RECEIVED

Affirmative
Affirmative

Affirmative
Affirmative

3

AEP

Michael E Deloach

Negative

3
3
3
3
3
3
3
3

Alabama Power Company
Ameren Services
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy

Robert S Moore
Mark Peters
Chris W Bolick
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo

Affirmative
Affirmative
Affirmative

SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz American
Electric Power)

Affirmative
Affirmative
Affirmative
Affirmative

3

City of Bartow, Florida

Matt Culverhouse

Negative

3

City of Clewiston

Lynne Mila

Negative

3
3
3
3
3
3
3

City of Farmington
City of Redding
City of Tallahassee
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York

Linda R Jacobson
Bill Hughes
Bill R Fowler
Michelle A Corley
Charles Morgan
John Bee
Peter T Yost

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS (FMPA (Florida
Municipal Power
Authority))

Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

NERC Standards
3
3
3
3
3

CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Entergy
FirstEnergy Corp.

Jose Escamilla
Kent Kujala
Connie B Lowe
Joel T Plessinger
Cindy E Stewart

3

Florida Municipal Power Agency

Joe McKinney

3
3
3

Florida Power & Light Co.
Florida Power Corporation
Georgia System Operations Corporation

Summer C Esquerre
Lee Schuster
Scott McGough

3

Great River Energy

Brian Glover

3
3
3
3
3

Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.

David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke

Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative

Affirmative
Affirmative

Kissimmee Utility Authority

Gregory D Woessner

Negative

3

Lakeland Electric

Mace D Hunter

Negative

3
3
3
3
3
3
3
3
3
3
3

Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District

Jason Fortik
Mike Anctil
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Roger Brand
Thomas C. Mielnik
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman

3
3
3

New York Power Authority

Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.

David R Rivera

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

Negative

Skyler Wiegmann

Affirmative

Ramon J Barany
David McDowell

Affirmative
Affirmative

Oklahoma Gas and Electric Co.

Donald Hargrove

Negative

3
3
3
3
3
3

Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Platte River Power Authority
PNM Resources

David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Terry L Baker
Michael Mertz

Affirmative
Affirmative

Portland General Electric Co.

Thomas G Ward

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)

Abstain
Affirmative

3

3

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Abstain

3

3

COMMENT
RECEIVED

SUPPORTS
THIRD PARTY
COMMENTS (NPCC
Submitted
Comments)

SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)

Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Previous
MOD’s have
specified the
allowable TTC
limits that can
be applied for
counter flow

NERC Standards
schedule)
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4

Jeffrey Mueller
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
Gregory J Le Grave
Michael Ibold
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy

4

Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding

4

City Utilities of Springfield, Missouri

John Allen

4

Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative

Tim Beyrle
Nicholas Zettel

Affirmative
Negative

4
4
4

Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Detroit Edison Company
Flathead Electric Cooperative

4

Florida Municipal Power Agency

Frank Gaffney

Negative

4

Fort Pierce Utilities Authority

Cairo Vanegas

Negative

4
4
4
4
4
4

Georgia System Operations Corporation
Herb Schrayshuen
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
WPPI Energy

Guy Andrews
Herb Schrayshuen
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh

Affirmative
Affirmative
Abstain
Affirmative

Henry E. LuBean

Affirmative

John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Todd Komplin

Affirmative
Affirmative
Affirmative

4

4
4
4
4
4
4
4
4
4
4

5

AEP Service Corp.

Margaret Powell

Abstain

Tracy Goble
Daniel Herring
Russ Schneider

Abstain
Affirmative
Abstain

Brock Ondayko

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency (FMPA))

Affirmative

Affirmative
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS - (I
support
someone else’s
comment:
Thomas Foltz –
American
Electric Power)

NERC Standards
5

Amerenue

Sam Dwyer

5

Arizona Public Service Co.

Scott Takinen

5
5
5

Matthew Pacobit
Steve Wenke
Clement Ma

Affirmative
Affirmative
Affirmative

Mike D Kukla

Affirmative

5

Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky
peak power plant project
Bonneville Power Administration

Francis J. Halpin

Affirmative

5

Brazos Electric Power Cooperative, Inc.

Shari Heino

5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Dominion Resources, Inc.
DTE Energy
Duke Energy
El Paso Electric Company
Electric Power Supply Association
Entergy Services, Inc.
Essential Power, LLC
Exelon Nuclear
First Wind
FirstEnergy Solutions

Chifong Thomas
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Mike Garton
Mark Stefaniak
Dale Q Goodwine
Gustavo Estrada
John R Cashin
Tracey Stubbs
Patrick Brown
Mark F Draper
John Robertson
Kenneth Dresner

5

Florida Municipal Power Agency

David Schumann

Negative

5

Great River Energy

Preston L Walsh

Negative

5
5

Hydro-Québec Production
JEA

Roger Dufresne
John J Babik

Abstain
Affirmative

5

Kansas City Power & Light Co.

Brett Holland

Negative

5

Kissimmee Utility Authority

Mike Blough

Negative

5

Lakeland Electric

James M Howard

Negative

5
5
5
5
5

Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
Nebraska Public Power District

Dennis Florom
Kenneth Silver
Karin Schweitzer
Rick Terrill
S N Fernando

Affirmative
Affirmative
Abstain
Affirmative

5

5
5
5
5

Negative

Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Abstain
Affirmative
Affirmative
Affirmative

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Abstain
Affirmative
Affirmative

David Gordon
Steven Grego
Mike Avesing
Don Schmit

SUPPORTS
THIRD PARTY
COMMENTS (Connemts
submitted by
AZPS)

Affirmative
Affirmative
Affirmative

COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ACES)

COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Association)

NERC Standards

5

New York Power Authority

Wayne Sipperly

Negative

5
5

NextEra Energy
Oglethorpe Power Corporation

Allen D Schriver
Bernard Johnson

Affirmative

5

Oklahoma Gas and Electric Co.

Henry L Staples

5
5
5

Omaha Public Power District
Orlando Utilities Commission
PacifiCorp

Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair

5

Portland General Electric Co.

Matt E. Jastram

5
5
5

Annette M Bannon
Tim Kucey
Steven Grega

5
5
5
5
5
5
5
5

PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.

5

Southern California Edison Company

Denise Yaffe

5
5
5
5

Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.

William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer

Affirmative
Affirmative
Affirmative

5

Tennessee Valley Authority

David Thompson

Negative

5
5
5
5
5
5
5

Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Westar Energy
Wisconsin Public Service Corp.
WPPI Energy
Xcel Energy, Inc.

Mark Stein
Melissa Kurtz
Erika Doot
Bryan Taggart
Scott E Johnson
Steven Leovy
Liam Noailles

Affirmative
Affirmative
Abstain
Affirmative
Abstain

5

Negative

SUPPORTS
THIRD PARTY
COMMENTS (NPCC
comments)

SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electrict)

Affirmative
Affirmative
Affirmative
Negative

COMMENT
RECEIVED

Affirmative
Affirmative

Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

COMMENT
RECEIVED

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Tom Foltz AEP)

Negative

COMMENT
RECEIVED

6

AEP Marketing

Edward P. Cox

6

Ameren Energy Marketing Co.

Jennifer Richardson

6

APS

Randy A. Young

6
6
6
6
6
6
6
6
6
6
6

Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
FirstEnergy Solutions

Brian Ackermann
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Kevin Querry

6

Florida Municipal Power Agency

Richard L. Montgomery

Negative

6

Florida Municipal Power Pool

Thomas Washburn

Negative

6

Florida Power & Light Co.

Silvia P Mitchell

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

COMMENT
RECEIVED

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative

Affirmative

COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

NERC Standards

6

Great River Energy

Donna Stephenson

Negative

6

Kansas City Power & Light Co.

Jessica L Klinghoffer

Negative

6

Lakeland Electric

Paul Shipps

Negative

6
6
6
6
6
6

Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water

Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley

6

New York Power Authority

Saul Rojas

6
6

Northern California Power Agency
Northern Indiana Public Service Co.

Steve C Hill
Joseph O'Brien

Abstain
Affirmative
Affirmative
Affirmative

Affirmative
Affirmative

Jerry Nottnagel

6
6
6
6
6
6
6
6
6
6
6
6
6

Kelly Cumiskey
Carol Ballantine
Stephen C Knapp
Elizabeth Davis
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Affirmative
Affirmative

John J. Ciza

Affirmative

6
6

PacifiCorp
Platte River Power Authority
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.

Michael C Hill
Benjamin F Smith II

Affirmative

6

Tennessee Valley Authority

Marjorie S. Parsons

Negative

6

Westar Energy
Western Area Power Administration - UGP
Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.

Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts
Department of Public Utilities
National Association of Regulatory Utility
Commissioners
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council

Grant L Wilkerson

6
6
8
8
8
8
9
9
10
10
10
10
10
10
10

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

Negative

Oklahoma Gas & Electric Services

6

Abstain

6

6

SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)

Negative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

COMMENT
RECEIVED

Peter H Kinney

David Hathaway
David F Lemmons
Edward C Stein
Roger C Zaklukiewicz
Frederick R Plett
Terry Volkmann

Abstain
Abstain
Affirmative
Affirmative
Affirmative

Donald Nelson

Affirmative

Diane J Barney

Affirmative

Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Steven L. Rueckert

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=c5fe3d8f-88b6-4223-825c-582765ca03e1[11/22/2013 12:00:37 PM]

Non-Binding Poll Results

Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Non-Binding Poll Results

Non-Binding Poll
Project 2012-05 ATC Revisions MOD A (MOD-001-2)
Name:
Poll Period: 11/8/2013 - 11/20/2013
Total # Opinions: 284
Total Ballot Pool: 351
80.91% of those who registered to participate provided an opinion or an abstention;

Summary Results: 79.11% of those who provided an opinion indicated support for the VRFs and VSLs.
Individual Ballot Pool Results

Segment

Organization

Member

1
1

Ameren Services
American Electric Power

Eric Scott
Paul B Johnson

1

Arizona Public Service Co.

Robert Smith

1
1
1
1
1
1
1

Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
BC Hydro and Power Authority
Bonneville Power Administration

John Bussman
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Patricia Robertson
Donald S. Watkins

1

Brazos Electric Power Cooperative, Inc.

1
1
1
1

Bryan Texas Utilities
John C Fontenot
CenterPoint Energy Houston Electric, LLC John Brockhan
Central Electric Power Cooperative
Michael B Bax
Central Maine Power Company
Joseph Turano Jr.
City of Tacoma, Department of Public
Chang G Choi
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Daniel S Langston
Clark Public Utilities
Jack Stamper
Cleco Power LLC
Danny McDaniel
Colorado Springs Utilities
Paul Morland
Consolidated Edison Co. of New York
Christopher L de Graffenried
CPS Energy
Richard Castrejana

1
1
1
1
1
1
1

Tony Kroskey

Opinions

Comments

Abstain
Negative

COMMENT
RECEIVED

Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative

Negative

Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

SUPPORTS
THIRD PARTY
COMMENTS (ACES Power
Marketing)

1
1
1
1
1
1
1
1

Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.

Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Pablo Onate
Oliver A Burke
William J Smith

1

Florida Keys Electric Cooperative Assoc.

Dennis Minton

1

Florida Power & Light Co.

Mike O'Neil

1

Gainesville Regional Utilities

Richard Bachmeier

1

Georgia Transmission Corporation

Jason Snodgrass

Affirmative
Affirmative
Abstain

Affirmative
Affirmative
Negative
Affirmative

Negative

Great River Energy

Gordon Pietsch

Negative

1
1
1

Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company
Holdings Corp
JDRJC Associates
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.

Ajay Garg
Martin Boisvert
Molly Devine

Affirmative
Affirmative

Michael Moltane

Affirmative

Jim D Cyrulewski
Ted Hobson
Walter Kenyon
Jennifer Flandermeyer

Affirmative
Affirmative
Affirmative

1
1
1
1

1

Lakeland Electric

1
1
1
1
1
1
1
1
1
1
1
1

Lee County Electric Cooperative
John Chin
Lincoln Electric System
Doug Bantam
Long Island Power Authority
Robert Ganley
Los Angeles Department of Water & Power John Burnett
Lower Colorado River Authority
Martyn Turner
M & A Electric Power Cooperative
William Price
Manitoba Hydro
Nazra S Gladu
MEAG Power
Danny Dees
MidAmerican Energy Co.
Terry Harbour
Minnkota Power Coop. Inc.
Daniel L Inman
Muscatine Power & Water
Andrew J Kurriger
N.W. Electric Power Cooperative, Inc.
Mark Ramsey

Non-Binding Poll Results
Project 2012-05 | November 2013

Larry E Watt

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)

Affirmative

1

1

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency (FMPA))

Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

2

1
1
1

1

1
1
1
1

National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power
Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy

Michael Jones
Cole C Brodine

Abstain
Abstain

Randy MacDonald

Bruce Metruck

Negative

Kevin White

Affirmative

David Boguslawski
Julaine Dyke
John Canavan

Affirmative
Affirmative
Abstain

1

Ohio Valley Electric Corp.

Robert Mattey

Negative

1

Oklahoma Gas and Electric Co.

Terri Pyle

Negative

1
1
1
1
1
1

Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
Platte River Power Authority

Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
John C. Collins

1

Portland General Electric Co.

John T Walker

1
1
1

Brenda L Truhe
Laurie Williams
Kenneth D. Brown

1
1
1

PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project

1

San Diego Gas & Electric

Will Speer

1
1
1
1

SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1

Wayne Guttormson
Pawel Krupa
Denise Stevens
Long T Duong

1

Non-Binding Poll Results
Project 2012-05 | November 2013

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

SUPPORTS
THIRD PARTY
COMMENTS (Thomas Foltz American
Electric Power)
SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)

Affirmative
Affirmative
Affirmative
Abstain
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS (PGE will enter
a separate
comment
regarding
counterflows.)

Affirmative
Affirmative
Abstain

Dale Dunckel
Denise M Lietz
Tim Kelley
Robert Kondziolka

Affirmative
Abstain
Affirmative
Negative

NO COMMENT
RECEIVED

Abstain
Affirmative
Affirmative
Affirmative

3

1
1

South Carolina Electric & Gas Co.
South Carolina Public Service Authority

Tom Hanzlik
Shawn T Abrams

1

Southern California Edison Company

Steven Mavis

1

Southern Company Services, Inc.

Robert A. Schaffeld

Affirmative
Affirmative

Negative

Affirmative

1

Southwest Transmission Cooperative, Inc. John Shaver

Negative

1

Sunflower Electric Power Corporation

Noman Lee Williams

Negative

1

Tampa Electric Co.

Beth Young

1

Tennessee Valley Authority

Howell D Scott

1
1
1
1
1
1
1

Trans Bay Cable LLC
Tri-State G & T Association, Inc.
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

2

BC Hydro

2
2

California ISO
Electric Reliability Council of Texas, Inc.

Steven Powell
Tracy Sliman
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley

2

Independent Electricity System Operator

Barbara Constantinescu

2
2
2
2
2
2
3
3
3
3
3
3
3
3
3

ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy

Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
Mark Peters
Chris W Bolick
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo

3

City of Bartow, Florida

Matt Culverhouse

Non-Binding Poll Results
Project 2012-05 | November 2013

SUPPORTS
THIRD PARTY
COMMENTS (FMPA (Florida
Municipal Power
Authority))

Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)
SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED

Affirmative
Abstain
Affirmative

Abstain
Affirmative
Abstain
Negative

COMMENT
RECEIVED

Affirmative

Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS -

4

3

City of Clewiston

Lynne Mila

3
3
3
3
3
3
3
3
3
3
3

City of Farmington
City of Redding
City of Tallahassee
Cleco Corporation
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Entergy
FirstEnergy Corp.

Linda R Jacobson
Bill Hughes
Bill R Fowler
Michelle A Corley
Charles Morgan
Peter T Yost
Jose Escamilla
Kent Kujala
Connie B Lowe
Joel T Plessinger
Cindy E Stewart

3

Florida Municipal Power Agency

Joe McKinney

3
3
3

Florida Power & Light Co.
Florida Power Corporation
Georgia System Operations Corporation

Summer C Esquerre
Lee Schuster
Scott McGough

3

Great River Energy

Brian Glover

3
3
3
3
3

Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.

David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke

Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative

COMMENT
RECEIVED

Affirmative
Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Abstain
Affirmative
Affirmative

3

Kissimmee Utility Authority

Gregory D Woessner

Negative

3

Lakeland Electric

Mace D Hunter

Negative

3
3
3
3
3
3
3

Lincoln Electric System
Jason Fortik
Los Angeles Department of Water & Power Mike Anctil
Louisville Gas and Electric Co.
Charles A. Freibert
M & A Electric Power Cooperative
Stephen D Pogue
Manitoba Hydro
Greg C. Parent
MEAG Power
Roger Brand
MidAmerican Energy Co.
Thomas C. Mielnik

Non-Binding Poll Results
Project 2012-05 | November 2013

(Florida
Municipal Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (fmpa)

SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

5

3
3
3
3

3

3
3
3

Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District

New York Power Authority

Northeast Missouri Electric Power
Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.

Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman

David R Rivera

Affirmative
Abstain
Abstain

Negative

Skyler Wiegmann

Affirmative

Ramon J Barany
David McDowell

Affirmative
Affirmative

3

Oklahoma Gas and Electric Co.

Donald Hargrove

Negative

3
3
3
3
3
3

Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Platte River Power Authority
PNM Resources

David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Terry L Baker
Michael Mertz

Affirmative
Affirmative

3

Portland General Electric Co.

Thomas G Ward

3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority

Jeffrey Mueller
Erin Apperson
Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant

Non-Binding Poll Results
Project 2012-05 | November 2013

SUPPORTS
THIRD PARTY
COMMENTS (NPCC
Submitted
Comments)

SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)

Affirmative
Affirmative

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Previous
MOD’s have
specified the
allowable TTC
limits that can
be applied for
counter flow
schedule)

Abstain
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

6

3
3
3
3
4
4
4
4
4

Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Xcel Energy, Inc.
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding

Mike Swearingen
Janelle Marriott
Bo Jones
Michael Ibold
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy

Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Tim Beyrle
Nicholas Zettel

Affirmative

4

City Utilities of Springfield, Missouri

John Allen

4
4
4

Consumers Energy Company
Detroit Edison Company
Flathead Electric Cooperative

Tracy Goble
Daniel Herring
Russ Schneider

4

Florida Municipal Power Agency

Frank Gaffney

4
4
4
4
4
4

Georgia System Operations Corporation
Herb Schrayshuen
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Public Utility District No. 1 of Douglas
County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power
Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
WPPI Energy
AEP Service Corp.
Amerenue

Guy Andrews
Herb Schrayshuen
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh

Affirmative
Affirmative
Abstain
Abstain

Henry E. LuBean

Affirmative

John D Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace

Abstain
Affirmative
Affirmative

4
4
4
4
4
4
4
4
4
4
5
5

Negative
Abstain
Affirmative
Abstain
Negative

Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Todd Komplin
Brock Ondayko
Sam Dwyer

Affirmative
Abstain

Abstain

Arizona Public Service Co.

Scott Takinen

5
5
5

Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky
peak power plant project

Matthew Pacobit
Steve Wenke
Clement Ma

Affirmative
Affirmative
Abstain

Mike D Kukla

Affirmative

Non-Binding Poll Results
Project 2012-05 | November 2013

COMMENT
RECEIVED

Affirmative

5

5

SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Negative

SUPPORTS
THIRD PARTY
COMMENTS (Comments
from AZPS)

7

5

Bonneville Power Administration

Francis J. Halpin

5

Brazos Electric Power Cooperative, Inc.

Shari Heino

5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

BrightSource Energy, Inc.
Chifong Thomas
City and County of San Francisco
Daniel Mason
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul A. Cummings
City of Tallahassee
Karen Webb
City Water, Light & Power of Springfield
Steve Rose
Cleco Power
Stephanie Huffman
Cogentrix Energy Power Management, LLC Mike D Hirst
Colorado Springs Utilities
Kaleb Brimhall
Consolidated Edison Co. of New York
Wilket (Jack) Ng
Consumers Energy Company
David C Greyerbiehl
CPS Energy
Robert Stevens
Dairyland Power Coop.
Tommy Drea
Dominion Resources, Inc.
Mike Garton
DTE Energy
Mark Stefaniak
Duke Energy
Dale Q Goodwine
El Paso Electric Company
Gustavo Estrada
Electric Power Supply Association
John R Cashin
Entergy Services, Inc.
Tracey Stubbs
Essential Power, LLC
Patrick Brown
First Wind
John Robertson
FirstEnergy Solutions
Kenneth Dresner

5

Florida Municipal Power Agency

David Schumann

Negative

5

Great River Energy

Preston L Walsh

Negative

5
5

Hydro-Québec Production
JEA

Roger Dufresne
John J Babik

Abstain
Affirmative

5

Kansas City Power & Light Co.

Brett Holland

Negative

5

Kissimmee Utility Authority

Mike Blough

Negative

5

Lakeland Electric

James M Howard

Negative

5
5

Lincoln Electric System
Dennis Florom
Los Angeles Department of Water & Power Kenneth Silver

Non-Binding Poll Results
Project 2012-05 | November 2013

Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (ACES)

Abstain
Affirmative
Affirmative
Affirmative

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Affirmative
Affirmative
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (ACES)

COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Agency)
SUPPORTS
THIRD PARTY
COMMENTS (Florida
Municipal Power
Association)

Abstain

8

5
5
5
5
5
5
5

Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale
Electric Company
MEAG Power
Muscatine Power & Water
Nebraska Public Power District

Karin Schweitzer
Rick Terrill
S N Fernando

Affirmative
Abstain
Affirmative

David Gordon

Abstain

Steven Grego
Mike Avesing
Don Schmit

Affirmative
Affirmative
Abstain

5

New York Power Authority

Wayne Sipperly

Negative

5
5

NextEra Energy
Oglethorpe Power Corporation

Allen D Schriver
Bernard Johnson

Affirmative

5

Oklahoma Gas and Electric Co.

Henry L Staples

5
5
5

Omaha Public Power District
Orlando Utilities Commission
PacifiCorp

Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair

5

Portland General Electric Co.

Matt E. Jastram

5
5
5

5
5
5
5
5
5
5
5

PPL Generation LLC
Annette M Bannon
PSEG Fossil LLC
Tim Kucey
Public Utility District No. 1 of Lewis County Steven Grega
Public Utility District No. 2 of Grant
Michiko Sell
County, Washington
Puget Sound Energy, Inc.
Lynda Kupfer
Sacramento Municipal Utility District
Susan Gill-Zobitz
Salt River Project
William Alkema
Santee Cooper
Lewis P Pierce
Seattle City Light
Michael J. Haynes
Seminole Electric Cooperative, Inc.
Brenda K. Atkins
Snohomish County PUD No. 1
Sam Nietfeld
South Carolina Electric & Gas Co.
Edward Magic

5

Southern California Edison Company

Denise Yaffe

5
5
5
5

Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.

William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer

Affirmative
Affirmative
Affirmative

5

Tennessee Valley Authority

David Thompson

Negative

5
5
5
5

Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
USDI Bureau of Reclamation
Wisconsin Public Service Corp.

Mark Stein
Melissa Kurtz
Erika Doot
Scott E Johnson

Affirmative
Affirmative
Abstain
Abstain

5

Non-Binding Poll Results
Project 2012-05 | November 2013

Negative

SUPPORTS
THIRD PARTY
COMMENTS (NPCC
comments)

SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)

Affirmative
Affirmative
Negative

COMMENT
RECEIVED

Affirmative
Affirmative

Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Negative

COMMENT
RECEIVED

COMMENT
RECEIVED

9

5
5
6
6

WPPI Energy
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.

Steven Leovy
Liam Noailles
Edward P. Cox
Jennifer Richardson

6

APS

Randy A. Young

6
6
6
6
6
6
6
6
6

Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Duke Energy
FirstEnergy Solutions

Brian Ackermann
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
Greg Cecil
Kevin Querry

6

Florida Municipal Power Agency

Richard L. Montgomery

Negative

6

Florida Municipal Power Pool

Thomas Washburn

Negative

6

Florida Power & Light Co.

Silvia P Mitchell

Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Great River Energy

Donna Stephenson

Negative

6

Kansas City Power & Light Co.

Jessica L Klinghoffer

Negative

6

Lakeland Electric

Paul Shipps

Negative

6
6
6
6
6
6

Lincoln Electric System
Eric Ruskamp
Los Angeles Department of Water & Power Brad Packer
Luminant Energy
Brenda Hampton
Manitoba Hydro
Blair Mukanik
Modesto Irrigation District
James McFall
Muscatine Power & Water
John Stolley
New York Power Authority

Saul Rojas

6
6

Northern California Power Agency
Northern Indiana Public Service Co.

Steve C Hill
Joseph O'Brien

SUPPORTS
THIRD PARTY
COMMENTS (ACES)
COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS (NPCC)

Affirmative
Affirmative

6

Oklahoma Gas & Electric Services

Jerry Nottnagel

Negative

6
6

PacifiCorp
Platte River Power Authority

Kelly Cumiskey
Carol Ballantine

Abstain

Non-Binding Poll Results
Project 2012-05 | November 2013

COMMENT
RECEIVED
SUPPORTS
THIRD PARTY
COMMENTS (FMPA)

Affirmative

6

6

COMMENT
RECEIVED

SUPPORTS
THIRD PARTY
COMMENTS (Oklahoma Gas
& Electric)

10

6
6
6

Stephen C Knapp
Elizabeth Davis
Peter Dolan

Affirmative
Affirmative

Hugh A. Owen

Affirmative

Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

John J. Ciza

Affirmative

6
6

Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan
County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and
Energy Marketing
Tacoma Public Utilities
Tampa Electric Co.

Michael C Hill
Benjamin F Smith II

Affirmative

6

Tennessee Valley Authority

Marjorie S. Parsons

Negative

6

Westar Energy
Grant L Wilkerson
Western Area Power Administration - UGP
Peter H Kinney
Marketing
Xcel Energy, Inc.
David F Lemmons
Edward C Stein
Roger C Zaklukiewicz
Massachusetts Attorney General
Frederick R Plett
Volkmann Consulting, Inc.
Terry Volkmann
Commonwealth of Massachusetts
Donald Nelson
Department of Public Utilities
Florida Reliability Coordinating Council
Linda Campbell
Midwest Reliability Organization
Russel Mountjoy
New York State Reliability Council
Alan Adamson
Northeast Power Coordinating Council
Guy V. Zito
ReliabilityFirst Corporation
Anthony E Jablonski
SERC Reliability Corporation
Joseph W Spencer
Western Electricity Coordinating Council
Steven L. Rueckert

6
6
6
6
6
6
6
6
6

6
6
8
8
8
8
9
10
10
10
10
10
10
10

Non-Binding Poll Results
Project 2012-05 | November 2013

COMMENT
RECEIVED

Affirmative

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

11

Individual or group. (28 Responses)
Name (15 Responses)
Organization (15 Responses)
Group Name (13 Responses)
Lead Contact (13 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT ENTERING
ANY ADDITIONAL COMMENTS, YOU MAY DO SO HERE. (8 Responses)
Comments (28 Responses)
Question 1 (0 Responses)
Question 1 Comments (20 Responses)
Question 2 (0 Responses)
Question 2 Comments (20 Responses)
Group
Northeast Power Coordinating Council
Guy Zito
The first sentence of the Purpose clearly conveys the purpose of the standard, making the
second sentence unneeded. The second sentence also creates confusion with the intent of the
standard by having the inconsistent wording “available transmission system transfer capability”
and “available transmission system capability” in the Purpose. We agree with the Independent
Experts recommendations that the requirement for developing a written methodology (or
methodologies) for determining TFC or TTC (as per R1) should be moved to a FAC standard, e.g.
FAC-013, if not already adequately covered by a related FAC standard. There is some degree of
overlap between R1 of the proposed MOD-001-2 and the FAC standard(s). Having two similar
requirements in two standards are unnecessary, and may result in a double jeopardy situation.
The SDT should remove, map or combine R1 with like requirements in the appropriate FAC
standard. The last bullet in Measure M1 is written as a requirement, not a measure. This bullet
stipulates that the Transmission Operator shall also be using their current method to
determine TFC or TTC. R1 requires the development of a methodology for determining TFC or
TTC, but does not require the use of the methodology to calculate TFC or TTC. If using the
developed methodology to determine TFC or TTC is a requirement, then it should be so
stipulated in R1, or in a new R2, but should not be embedded in a measure. We also agree with
the Independent Experts’ recommendations to remove the requirements for developing an
AFCID or ATCID (R2, in the proposed MOD-001-2), or to request NAESB to adopt or develop
these requirements in their business practices. These IDs are intended for calculating the AFCs
or ATCs for business usage, and do not contribute to ensuring BES reliability. We suggest to
remove R2 from the proposed standard. With regard to the preceding comments, suggest
removing all references to ATC and AFC in Requirements R5 and R6. Requirement R3 stipulates
that the TSP develop a Capacity Benefit Margin Implementation Document (CBMID) that
describes its method for establishing CBM. R3 does not stipulate the requirement for the TSP
to determine CBM values. Measure M3 implies that the TSP shall determine CBM values using
the developed CBMID, and asks current CBM values, or other evidence (such as written
documentation, study reports, or supporting information) to demonstrate that it established

CBM values consistent with its methodology described in the CBM. The requested evidence
does not correspond with the requirement. Therefore, either the requirement needs to be
expanded to stipulate the TSP’s obligation in determining CBM values, or M3 be revised to
remove references to CBM values. Suggest the latter approach since determination of the CBM
values is part of ATC calculation which is regarded a business practice that should be addressed
by or mapped to NAESB standards. The preceding comment also applies to Requirement R4,
except in this case, it is the TOP’s Transmission Reliability Margin Implementation Document
(CBMID). R5 is prone to requests for interpretation, as witnessed in a number of past
interpretation requests on requirements that stipulate two separate Responsible Entities being
held accountable for two different tasks (TOP and BA in some TOP standards). R5 as presented
will likely invite requests for interpretation on which entity is responsible for what part of the
requirement. Suggest that the SDT consider splitting this requirement into two requirements –
one for the TSP to respond to requests on CBMID, and one for the TOP to respond to requests
on TRMID and TFC/TTC methodology. The comment regarding the potential for requests for
interpretation for requirements that stipulate two separate Responsible Entities being held
accountable for two different tasks also applies to R6. The need for R6 should be reviewed in
accordance with the Purpose of the standard, and the intent of Requirements R3 and R4, as
commented above. Are the two requirements to stipulate the development of the CBMID and
the TRMID only? Or are they also intended to stipulate the requirements for calculating CBM
values and TRM values using the established methodologies? If it is the former, then there
should not be any request for and response to requests for data provision. If it the the latter,
then R3 and R4 need to be revised to clearly stipulate the obligations for calculating such
values. The Purpose statement of the standard does not appear to support the latter. Also, as
indicated in the preceding comments, determination of CBM values and TRM values is part of
ATC calculation which is regarded a business practice that should be addressed by or mapped
to NAESB standards.
Individual
Thomas Foltz
American Electric Power
AEP objects to the inclusion of the Transmission Operator as an applicable Functional Entity.
Though the draft was improved somewhat by the recently proposed qualifier to R1 regarding
Transmission Operators “that determines Total Flowgate Capability (TFC) or Total Transfer
Capability (TTC)”, it still puts entities in a position of having to prove to an auditor that their
Transmission Operators do not perform this work. AEP has previously been in the position of
proving to an auditor that we *don’t* perform certain work functions, and “proving a negative”
can be challenging. If Transmission Operator is retained as a Functional Entity, we believe it
would be preferable to instead state “Each Transmission Operator or Transmission Service
Provider that determines Total Flowgate Capability (TFC) or Total Transfer…”
Though we support the overall efforts of the drafting team and the integration and
consolidation of the proposed standards, AEP is choosing to vote negative on this project due
to our objection to the Transmission Operator as an applicable Functional Entity. Although the
most recent changes were beneficial in that regard, we believe it would be preferable to

qualify R1 to state “Each Transmission Operator or Transmission Service Provider that
determines Total Flowgate Capability (TFC) or Total Transfer…”
Individual
Kathleen Goodman
ISO New England, Inc.
Agree
IRC SRC
Individual
Michael Falvo
Independent Electricity System Operator
1. We do not support the second sentence in the Purpose Section since the first sentence
already clearly conveys the purpose of the standard. The second sentence is totally
unnecessary. In fact, it creates a confusion of the intent of the standard, notwithstanding that
there are inconsistent wording between “available transmission system transfer capability” and
“available transmission system capability” throughout the Purpose Section. 2. We do not agree
with the proposed revision to MOD-001-2 standard in the following aspects: a. We agree with
the Independent Experts recommendations that the requirement for developing a written
methodology (or methodologies) for determining TFC or TTC, i.e. R1, should be moved to an
FAC standard, e.g. FAC-013, if not already adequately covered by the related FAC standard.
There is some degree of overlap between R1 of the proposed MOD-001-2 and the FAC
standard(s). Having two similar requirements in two standards are unnecessary, and may result
in double-jeopardy. We urge the SDT to remove or map or combined R1 with like requirements
in the appropriate FAC standard. b. Notwithstanding the above suggestion, we find the last
bullet in Measure M1 to be a requirement, not a measure. This bullet stipulates that the
Transmission Operator shall also be using their current method to determine TFC or TTC. R1
requires the development of a methodology for determining TFC or TTC, but does not require
the use of the methodology to calculate TFC or TTC. If using the developed methodology to
determine TFC or TTC is a requirement, then it should be so stipulated in R1, or in a new R2,
but should not be imbedded in a measure. c. We also agree with the Independent Experts
recommendations to remove the requirements for developing an AFCID or ATCID (R2, in the
proposed MOD-001-2), or to request NAESB to adopt or develop these requirements in their
business practices. These IDs are intended for calculating the AFCs or ATCs for use by business
activities and thus do not contribute to ensuring BES reliability. We suggest to remove R2 from
the proposed standard. d. In connection to the above comments, we suggest removing all
references to ATC and AFC in Requirements R5 and R6. e. Requirement R3 stipulates that the
TSP develop a Capacity Benefit Margin Implementation Document (CBMID) that describes its
method for establishing CBM. R3 does not stipulate the requirement for the TSP to determine
CBM values. Measure M3 implies that the TSP shall determine CBM values using the developed
CBMID, and asks current CBM values, or other evidence (such as written documentation, study
reports, or supporting information) to demonstrate that it established CBM values consistent
with its methodology described in the CBM. The requested evidence does not correspond with
the requirement. Therefore, either the requirement needs to be expanded to stipulate the

TSP’s obligation in determining CBM values, or M3 be revised to remove references to CBM
values. We suggest the latter approach since determination of the CBM values is part of ATC
calculation which is regarded a business practice that should be addressed by or mapped to
NAESB standards. f. The above comment also applies to Requirement R4, except in this case, it
is the TOP’s Transmission Reliability Margin Implementation Document (CBMID). g. We find R5
to be prone to requests for interpretation, as witnessed in a number of past interpretation
requests on requirements that stipulate two separate Responsible Entities being held
accountable for two different tasks (TOP and BA in some TOP standards). R5 as presented will
likely invite requests for interpretation on which entity is responsible for what part of the
requirement. We strongly suggest that the SDT consider splitting this requirement into two
requirements – one for the TSP to respond to requests on CBMID, and one for the TOP to
respond to requests on TRMID and TFC/TTC methodology. h. The comment in (g) regarding the
potential for requests for interpretation for requirements that stipulate two separate
Responsible Entities being held accountable for two different tasks also apply to R6.
Notwithstanding this comment, the need for R6 should be reviewed in accordance with the
purpose of the standard, and the intent of Requirements R3 and R4, as commented above. Are
the two requirements to stipulate the development of the CBMID and the TRMID only? Or are
they also intended to stipulate the requirements for calculating CBM values and TRM values
using the established methodologies? If it is the former, then there should not be any request
for and the response to requests for data provision. If it the the latter, then R3 and R4 need to
be revised to clearly stipulate the obligations for calculating such values. The purpose
statement of the standard does not appear to support the latter. Also, as indicated in
Comments (e) and (f), above, determination of CBM values and TRM values is part of ATC
calculation which is regarded a business practice that should be addressed by or mapped to
NAESB standards.
Group
Oklahoma Gas & Electric
Terri Pyle
OG&E still strongly agree with the reasoning made by Florida Municipal Power Agency (in the
initial ballot) on removing TOP from being responsible for TTC/TFC and TRM calculations.
Therefore, we suggest the following changes: • From the applicability section 4.1.1 remove
Transmission Operator. • R1, change the responsibility from the TOP to the TSP. We recognize
that this change would also requires conforming changes to the NERC Functional Reliability
Model responsibilities of the TOP and TSP. The NERC Reliability Functional Model states that
the TTC/TFC calculation is the responsibility of the TOP. Note: Refer to NERC's Reliability
Functional Model document (Version 5, November 2009). Pages 37-39 describe Transmission
Operator’s function and tasks. • R4, change the responsibility from the TOP to the TSP. We’re
also proposing conforming changes to the TRMID definition in the NERC Glossary of Terms. The
approved TRMID definition (below) in the NERC Glossary of Terms indicates that TRM
calculation is the responsibility of the TOP. The TRMID definition should change from
“…Transmission Operator’s calculation of TRM” to “…Transmission Services Provider’s
calculation of TRM.” TRMID (NERC Glossary of Terms): A document that describes the

implementation of a Transmission Reliability Margin methodology, and provides information
related to a Transmission Operator’s calculation of TRM. • R5 and R6, change the
responsibilities to refer only to the Transmission Service Provider (TSP).
Group
Arizona Public Service Company
Janet Smith
1.R1.3.1 implies that the constraints that are requested by the other TOP needs to be included.
It is not clear if it applies only to thermal constraints or if it also applies to other constraints
such as voltage. R1.3.1 and R1.3.2 seems to imply that it only applies to thermal since it refers
to distribution factor, if this is the intent R1.3 needs to be clarified as such. 2.It is not clear what
needs to be included in ATCID to comply with R2.1.3 and this should be clarified to this effect.
3.It is not clear why separate documents are required for ATC, CBM, and TBM. CBM and TBM
should be included in ATCID document and thus R3 and R4 should be merged into R2.
R5 and R 6 both refer to responding for a request from other TOP. It would be best if it is
combined into a single requirement or omitted since they are administrative in nature and not
a true reliability requirement.
Group
MRO NERC Standards Review Forum
Russ Mountjoy
The revised Purpose section references “Bulk Power System”, the NSRF suggests that it should
be changed to “Bulk Electric System”. The NSRF recommends this due to the new BES
definition will “pull in” any <100 Kv systems that MOD-001-2 would be applicable too.
Individual
David Jendras
Ameren
Agree
We support SERC Planning Standards Subcommittee (PSS) comments
Individual
Romel Aquino
Southern California Edison
Agree
FMPA (Florida Municipal Power Authority)
Group
ISO/RTO Standards Review Committee
Greg Campoli
1. The drafting team has revised MOD-001-2 in response to stakeholder comments and
suggestions. If you do not agree or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestions in your comments. 0 Yes 0 No
Comments: PURPOSE 1. The SRC can support the revised Purpose statement if it were limited

to the first sentence as the first sentence clearly conveys the purpose of the standard. The
proposed second sentence is unnecessary and creates confusion as to the intent of the
standard. Moreover, the SRC is concerned with the inconsistent wording in sentence 2
regarding the terms “available transmission system transfer capability” and “available
transmission system capability”. REQUIREMENTS 2. We do not agree with the proposed
revision to MOD-001-2 standard in the following aspects: a. We find the last bullet in Measure
M1 to be a requirement, not a measure. This bullet stipulates that the Transmission Operator
shall use their current method to determine TFC or TTC. R1 requires the development of a
methodology for determining TFC or TTC, but does not require the use of the methodology to
calculate TFC or TTC. If using the developed methodology to determine TFC or TTC is a
requirement, then it should be so stipulated in R1, or in a new R2, but should not be imbedded
in a measure. b. We find R5 to be prone to requests for interpretation, as witnessed in a
number of past interpretation requests on requirements that stipulate two separate
Responsible Entities being held accountable for two different tasks (TOP and BA in some TOP
standards). R5 as presented will likely invite requests for interpretation on which entity is
responsible for what part of the requirement. The SRC recommends splitting this requirement
into two requirements – one for the TSP to respond to requests on CBMID, and one for the TOP
to respond to requests on TRMID and TFC/TTC methodology. c. The above comment to R5
regarding the potential for requests for interpretation for requirements that stipulate two
separate Responsible Entities being held accountable for two different tasks also applies to R6.
Notwithstanding this comment, the need for R6 should be reviewed in accordance with the
purpose of the standard, and the intent of Requirements R3 and R4, as commented above. Are
the two requirements to stipulate the development of the CBMID and the TRMID only? Or are
they also intended to stipulate the requirements for calculating CBM values and TRM values
using the established methodologies? If it is the former, then there should not be any request
for and the response to requests for data provision. If it the the latter, then R3 and R4 need to
be revised to clearly stipulate the obligations for calculating such values. The purpose
statement of the standard does not appear to support the latter. [R1.1] - 1.1 states, “pre- and
post-contingency state:” Is there a formal NERC definition for post contingent state? Is it up to
the TOP to define the post-contingency state? [R1.2] - We believe that 1.2.1 and 1.2.5 maybe
applicable to TTC but not TFC. Can we say these provisions are not applicable to TFC?
Currently, there’s no clear indication that we can state that they are not applicable to TFC. We
suggest revising the language to clearly state that if it’s not applicable to TFC then state it’s not
applicable to TFC. [M1] - “Simulation being used to find the max TFC or TTC that remains within
the limit” – this is not applicable to Flowgate methodology. Can we state as such? Currently,
there’s no clear indication that we can state that they are not applicable to TFC. We suggest
revising the language to clearly state that if it’s not applicable to TFC then state it’s not
applicable to TFC. “The application of a distribution factor in determining if a limit affects the
TFC or TTC value” – this is not applicable to Flowgate methodology. Can we state as such?
Currently, there’s no clear indication that we can state that they are not applicable to TFC. We
suggest revising the language to clearly state that if it’s not applicable to TFC then state it’s not
applicable to TFC. “A statement that the monitoring of a select limit(s) results in the TFC or TTC
not exceeding another set of limits” What does “another set of limits” means? Should there be

additional description to add more clarity? [R2] - 2.1.4 states, “Planned outages;” Why not also
include forced outages or other known outages? (same comment applies to 1.2.4) 2.2 states
“for reliability constraints”. We suggest changing this to “for reliability-related constraints” to
be consistent with the language in 1.3. VRF / VSLs Table of Compliance Elements: [R1(VSL)] We suggest moving the following from High VSL to Moderate “Each Transmission Operator that
determines TFC or TTC has not described the process for including any reliability-related
constraints that have been requested by another Transmission Operator, provided the
constraints are also used in the requesting Transmission Operator’s TFC or TTC calculation and
the request referenced” [R1(VSL)] - We suggest moving the following from High VSL to
Moderate “Each Transmission Operator that determines TFC or TTC has not used (i) an impact
test process for including requested constraints, (ii) a process to account for requested
constraints that have a five percent or greater distribution factor for a transfer between areas
in the TTC determination, or (iii) a mutually agreed upon method for determining whether
requested constraints need to be included in the TFC or TTC determination. (1.3.1, 1.3.2,
1.3.3)” [R2(VSL)] - We suggest moving the following from High VSL to Low because the TSP is
still calculating AFCs “Each Transmission Service Provider that uses the Flowgate Methodology
did not use the AFC determined by the Transmission Service Provider for reliability constraints
identified in part
ERCOT abstained from signing on to these comments because the standard does not apply to
them. PJM will submit its own comments.
Individual
Shirley Mayadewi
Manitoba Hydro
Manitoba Hydro is in general agreement with the standard but we have the following
comments: (1) Purpose – the language fluctuates between available transmission system
capability and available transmission system transfer capability. Unless these are meant to
refer to two different things, a consistent reference should be used. (2) R1, 1.3 – it would be
more accurate if the opening line said ‘….the process for determining whether to include any
reliability related constraints…’ as opposed to ‘…including any reliability related constraints’
because it may be that it is determined that they not be included. (3) R1, 1.3.2 – the words ‘in
its methodology’ are missing after the word ‘describe’. (4) M1 – there doesn’t seem to be any
measure related to the requirement in 1.3.3. (5) R2 , 2.1 – suggest changing ‘that’ to ‘provided
that such elements’ in the opening lines of 2.1 (6) R2, 2.2 – R2 is focused on Transmission
Service Providers and their methodologies. However, there is a cross reference to reliability
constraints identified in part 1.3 and part 1.3 doesn’t apply to TSPs, only TOs. Will this creates a
gap, or would TOs have the same information as TSPs would have? (7) M2 – the requirement in
R2 is to document current practice. The last bullet of M2 is about measuring whether or not
the TSP is using its current method. It would be more closely aligned with the requirement
itself if this bullet was phrased in a way that referred to the methodology being reflective of
actual current method. The evidence could be the same. (8) M3 – the requirement refers to
TSPs that ‘determine’ CBM as does the first clause of the measure. However, then the measure
refers to the TSPS that don’t ‘maintain’ CBM– this language should be consistent. (9) R5 – no

guidance given as to what ‘demonstrating a reliability need’ is and how this should be assessed.
Presumably this is in the responsible entity’s sole judgment. (10) M5- the punctuation in this
sentence results in the measure not matching the requirement. It should be rewritten as
follows: Examples of evidence include, but are not limited to, dated records of the request
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission
Planner, Transmission Service Provider, or another registered entity who demonstrates a
reliability need, and the Transmission Service Provider’s response to the request, or if no
requests have been received, a statement by the Transmission Service Provider that they have
received no requests. (11) R6 – no guidance given as to what ‘on an ongoing basis’ means. The
word ‘beginning’ should be added after the words ‘on an ongoing basis’. 6.1 has deleted the
words ‘at regular intervals’ while the measure still contains these words. (12) Compliance 1.3 The language refers specifically to a process found in the NERC Rules of Procedure. Generally in
draft standards, there is just a list of processes that may be used. The reference is concerning
because MB Hydro has their own Compliance and Monitoring program and has only adopted
select aspects of the NERC Rules of Procedure. (13) VSLs, R1, High VSLs – ‘Any’ could be
interpreted to mean ‘any one of’ while in this case it seems to be intended to refer to all of the
limitations. (14) VSL, R3 – the language of the requirement is ‘determines’ CBM values, while
the language of the VSL is ‘uses’ CBM values. Also, in the requirement it refers to the CBMID
describing the method for establishing CBM, while the VSL uses the word determines. The
language should be consistent between the requirement and the VSL. (15) VSL, R4 – same
comment as VSL, R3 above. (16) VSL, R5 – the requirement is to provide a written response
while the VSL refers only to ‘respond’.
Group
Bonneville Power Administration
Jamison Dye
BPA supports the draft standard as written.
Individual
Angela P Gaines
Portland General Electric Company
Previous MOD’s have specified the allowable TTC limits that can be applied for counter flow
schedules. There should be more required in MOD-A to provide some level of guidance for
schedules in the direction counter to prevailing flows.
Individual
Brett Holland
Kansas City Power & Light
We previously commented that the term “used by” was vague with respect to whether or not a
TOP needed a TFC/TTC methodology in Requirement 1. In this version, it has been change to
“Each TOP that determines” TTC/TFC. We would argue that "determining" would be the actual
act of calculating and that since some registered entities do not make these calculations, then
those REs would not need a methodology. R1.3.1 and 1.3.2 still reference the TOP that “uses” a

specific methodology. This is still too vague of terminology for standard language.
Individual
Richard Vine
California ISO
Agree
ISO/RTO Standards Review Committee
Individual
Anthony Jablonski
ReliabilityFirst
Even though ReliabilityFirst votes in the Affirmative, ReliabilityFirst believes a comment
submitted through the last comment period was either overlooked or not addressed.
ReliabilityFirst believes the proposal lacks any measurement of whether the communication of
availability of transmission service is accurate. Checking that the calculations conform to a
methodology does not assure accuracy. ReliabilityFirst believes the addition of a requirement
to verify that past communications of service availability were accurate would be an
improvement. Since these values are predictive, and cannot be 100% accurate, there needs to
be some measure of the quality of communication or even that it was satisfactory. For
consideration, ReliabilityFirst recommends a requirement for periodic analysis of the accuracy
of the communication of transmission service availability.
Group
SPP Standards Review Group
Robert Rhodes
Yes We suggest that the reference to the Bulk Power System (BPS) in the Purpose be changed
to the Bulk Eletric System (BES). In the Rationale Box for R1, capitalize Real-time. In the
Rationale Box for R6, there are a couple of instances where ‘is’ is used as the verb with TOP and
TSP. This should be changed to ‘are’. Also, we suggest the following change in the 2nd
sentence: ‘…modify that data from the form in which they use or maintain it.’
We appreciate the effort the drafting team has made in modifiying the proposed standard and
believe the current proposal is an improvement over the previous version.
Group
SERC Planning Standards Subcommittee
Jim Kelley
Yes. Current language for Measure 1, 4th sub-bullet: (1.3) A copy of the request and a
description of the method used to perform the impact test (1.3.1) or account for the requested
constraints (1.3.2). Suggested modification for Measure 1, 4th sub-bullet: (1.3) A copy of the
request and a description of the method used to perform the impact test (1.3.1), or account for
the requested constraints (1.3.2), or a description of a different method used (1.3.3). The SDT is
respectfully requested to review the term “determines” in R3 for possible replacement by
“maintains”. Current R3 language: Each Transmission Service Provider that determines
Capacity Benefit Margin (CBM) values shall develop a Capacity Benefit Margin Implementation

Document (CBMID) that describes its method for establishing CBM. The method described in
the CBMID shall reflect the Transmission Service Provider’s current practices for determining
CBM values. Suggested R3 modification: Each Transmission Service Provider that DELETE:
determines ADD: “maintains” Capacity Benefit Margin (CBM) values shall develop a Capacity
Benefit Margin Implementation Document (CBMID) that describes its method for establishing
CBM. The method described in the CBMID shall reflect the Transmission Service Provider’s
current practices for determining CBM values.
The SDT is requested to either change the term “affidavit” or add the term “attestation” to M3
and M4. An example follows for the SDT consideration of one option: Current M3 language:
M3. Each Transmission Service Provider that determines CBM shall provide evidence, including,
but not limited to, its current CBMID, current CBM values, or other evidence (such as written
documentation, study reports, or supporting information) to demonstrate that it established
CBM values consistent with its methodology described in the CBMID. If a Transmission Service
Provider does not maintain CBM, examples of evidence include, but are not limited to, an
affidavit, statement, or other documentation that states the Transmission Service Provider
does not maintain CBM. Possible M3 language modification by adding “attestation”: M3. Each
Transmission Service Provider that determines CBM shall provide evidence, including, but not
limited to, its current CBMID, current CBM values, or other evidence (such as written
documentation, study reports, or supporting information) to demonstrate that it established
CBM values consistent with its methodology described in the CBMID. If a Transmission Service
Provider does not maintain CBM, examples of evidence include, but are not limited to, an
affidavit, ADD: “attestation”, statement, or other documentation that states the Transmission
Service Provider does not maintain CBM. The comments expressed herein represent a
consensus of the views of the above named members of the SERC Planning Standards
Subcommittee (PSS) only and should not be construed as the position of the SERC Reliability
Corporation, or its board or its officers.
Individual
Jason Snodgrass
Georgia Transmission Corporation
GTC agrees in general but thinks that alternative language would provide more clarity in some
places shown below. For R2, replace "determine" with "establish": R2.Each Transmission
Service Provider that establishes Available Flowgate Capability (AFC) or Available Transfer
Capability (ATC) shall: Relocate "Develop an ATCID..." to R2.1: 2.1. Develop an Available
Transfer Capability Implementation Document (ATCID) that describes the methodology (or
methodologies) it uses to establish AFC or ATC values. Each methodology shall describe the
method used to account for the following elements that impact the establishment of AFC or
ATC: The last bullet item for M2 seems to be an additional Requirement which is not listed in
R2 or in its sub-requirements. Please either remove, clarify the intent, or create a new R2.2 to
correspond such as: 2.2. Demonstrate that current AFC or ATC values are established in
accordance with the current methodology (or methodologies) developed using R2.1. If the SDT
decides to accept the proposed R2.2, then increment the existing R2.2 to R2.3 and replace
"determined" with "established" For 2.3. Each Transmission Service Provider that uses the

Flowgate Methodology shall, for reliability constraints identified in part 1.3, use the AFC
established by the Transmission Service Provider for that constraint. For R3, the last sentence is
somewhat confusing and could easily be clarified/simplified. R3. Each Transmission Service
Provider that establishes Capacity Benefit Margin (CBM) values shall develop a Capacity Benefit
Margin Implementation Document (CBMID) that describes its method for establishing CBM.
The Transmission Service Provider shall demonstrate that current CBM values are established
in accordance with the current CBMID. For R4, the last sentence could be clarified/simplified.
R4. Each Transmission Operator that determines establishes Transmission Reliability Margin
(TRM) shall develop a Transmission Reliability Margin Implementation Document (TRMID) that
describes its method for establishing TRM. The Transmission Operator shall demonstrate that
current TRM values are established in accordance with the current TRMID. For VRF/VSLs: GTC
suggest making the corresponding changes as mentioned above with respect to use of the
terms "determine" "establish", and other clarifying changes, etc.
Individual
Oliver Burke
Entergy Services, Inc.
Agree
Entergy Transmission supports the comments provided by SERC's Planning Standards
Subcommittee.
Individual
Steven Mavis
Southern California Edison Company
Agree
FMPA (Florida Municipal Power Authority)
Group
ACES Standards Collaborators
Ben Engelby
(1) We appreciate the drafting team’s effort in consolidating the MOD standards. In addition,
we generally agree with the refinements to the standard from the previous draft. There are a
few items that we believe can be improved, as stated below. (2) For R1, we suggest the SDT
delete parts 1.1.1 through 1.1.4 because they are SOLs. We do not see the need to have a subpart 1.1.5 to include “other SOLs” because the NERC term will encompass all sub-parts 1.1.1
through 1.1.4. These sub-parts should be removed and the requirement should reference SOLs.
(3) For R1, part 1.3, who determines the proper constraints from another TOP? Is it the TOP
who makes the request first? What if those constraints do not apply to another TOP? How is it
possible that one TOP has authority over another TOP? This requirement needs further
refinement to clarify what is needed for reliability purposes. If two entities are registered for
the same function, there should be equal authority and coordination should occur to
determine if there are any reliability-related constraints. (4) For R1, part 1.3.3, we believe this
approach is reasonable. The only area of difficulty for compliance purposes is what evidence
needs to be maintained. We ask that the drafting team provide a measure for this agreement

among the TOPs. Evidence could include emails, attestations, meeting minutes, or other
agreements between the TOPs. (5) For R2, the requirement should reflect that once TTC/TFC is
complete per R1, then determining AFC/ATC could be a simple algebraic calculation. The
requirement as written, in parts 2.1.1 through 2.1.7, implies another load flow study must be
performed to calculate AFC/ATC, which may not be necessary. (6) For R3 and R4, we
recommend adding attestation in the measure for entities that do not determine CBM or TRM.
We recommend changing affidavit to attestation so the measures reflect current industry
practices for maintaining compliance evidence. Affidavits generally refer to sworn statements
given during a legal proceeding and have additional requirements such as being notarized. We
do not think it is proper to use affidavit and ask the drafting team to use attestation instead.
Use of attestations is consistent with the “note to auditor” section in the RSAW for
requirements R3 and R4. (7) For R6, this requirement meets Paragraph 81 criteria because it is
administrative, focuses on data collection activities, and requires periodic updates that do not
directly support reliability. This requirement should be struck in its entirety.
(1) While we appreciate the compliance input for this standard, we would ask that the drafting
teams reach out to compliance during the informal development process and post compliance
guidance and a draft RSAW with the draft standard during the initial posting. This material is
important to the commenting process and having all information at the outset may alleviate
some of industry’s concerns. (2) In the compliance guidance document, there are several
statements that the auditors will be focusing on the most recent values instead of historical
evidence and the audit teams will be looking “forward” to ensure an entity is following its
methodology to determine a given value. We support this approach since it is consistent with
the Reliability Assurance Initiative (RAI). In light of the RSAW, we question the need for the
standard to require a five years evidence retention period for implementation and
methodology documents (MOD-001-2, Section C Compliance, Part 1.2 Evidence Retention). The
TOP will be audited every three years, so having five years of evidence is unnecessary because
the documents older than three years will already have been reviewed in a prior audit. If
compliance auditors are only going to be verifying the most recent methodology, then that is
all that should be retained. We recommend modifying the compliance evidence retention
section to reflect the NERC compliance department approach. (3) The VSLs use the term
“current” for severe violations. While we can understand the rationale of not having a written
methodology may meet a severe category, using the term “current” could potentially result in
negative impacts for enforcement. It would appear that if an entity did not include one
limitation in its methodology that would be a lower VSL. However, if circumstances changed
that required an entity to add a limitation but did not (still only one limitation not included),
then its written methodology would not be current, resulting in a severe violation. We
recommend removing the “current” methodology from VSLs because it could be
misinterpreted. (4) Thank you for the opportunity to comment.
Group
Tennessee Valley Authority
David Thompson
TVA recognizes the tremendous effort put forth by the Standard Drafting Team in order to

draft completely new transfer capability standards in such a short time period. TVA also
understands the significance of the goal of the drafting team to make the MOD standards less
onerous and complicated while still maintaining the focus on system reliability. It is our opinion
that the new MOD standards in MOD-A have moved too far towards a fill-in-the-blank type
standard and do very little to maintain the reliability of transfer capability calculations. The few
requirements that do help maintain the reliability of the transfer capability calculations do not
apply to everyone and therefore unfairly punish entities use more accurate methodologies
such as AFC. For example, R2. 2.2 states, “Each Transmission Service Provider that uses the
Flowgate Methodology shall, …use the AFC determined by the Transmission Service Provider
for that constraint.” The requirement is essentially optional because it only applies to entities
that use the flowgate methodology, yet has a High Violation Severity Level. An essentially
optional requirement should not be considered a High VSL. TVA recognizes the importance of
sharing AFC data and support the requirement’s intentions. But if the requirement is only going
to apply to some entitles that choose to use the AFC method then the requirement should be a
Low VSL. Also, it should be recognized that these AFC processes are automated processes and
some leeway should be given to processing errors. At times these processes have hiccups, e.g.
when a flowgate name changes occur with model changes, AFC overrides could be potentially
missed. A tiered approach to the Severity Level may make more sense with some room for
processing errors. TVA also feels that the requirement could be reworded to recognize the fact
that an entity can only use AFCs that are provided to it by the neighboring entity. If AFCs are
not provided then they should not be required to be used. The language could be changed to,
“each Transmission Service Provider that uses the Flowgate Methodology shall, for reliability
constraints identified in part 1.3, use the AFC if provided by the Transmission Service Provider
for that constraint.” The same logic applies to the TRM and CBM methodologies. Using CBM
and TRM increase the reliability of the system, but those entities that choose to use TRM and
CBM are unfairly singled out to Severe Violation Severity Level requirements. By not having
CBM and TRM you potentially decrease system reliability and at the same time decrease your
compliance risk. If the Standard Drafting Team truly feels that TRM and CBM are not reliability
requirements then they requirements should not exist. If the TRM and CBM requirements are
just going to be fill-in-the-blank transparency type requirements then they should not have
Severe Violation Severity Levels. Because of the change of the MOD standards to more of a fillin-the-blank type standard and the incorrect application of compliance risk, such that those
entities that try to increase the reliability of their transfer capability calculations end up
increasing their compliance risk, TVA votes “No” on the Project 2012-05 ATC Revisions (MOD
A).
Group
Florida Municipal Power Agency
Frank Gaffney
FMPA continues to vote Negative for the MOD-001, MOD A project for one primary reason.
FMPA believes strongly that the TSP should be the entity that calculates TTC/TFC and TRM and
not the TOP. We also believe strongly that TTC/TFC/TRM are commercial values and not
reliability values. As such, FMPA believes that this standard eventually belongs within the

NAESB business practice standards and not the NERC reliability standards. If the TTC/TFC/TRM
calculations are not assigned to the TSP and remain with the TOP, this transition to NAESB will
not likely happen. There are many reasons that FMPA believes that TTC/TFC/TRM are
commercial in nature and not reliability in nature: 1. Nowhere in the standards are TOPs or RCs
required to operate to TTC/TFC. Instead they are required to operate to SOLs and IROLs. If
TTC/TFC were reliability in nature, there would be a requirement in the standards to operate to
them. Even in the NAESB standard (WEQ-008) on Transmission Loading Relief (TLR),
transactions are not curtailed if TTC/TFC is exceeded, but rather only when SOLs are exceeded.
2. TTC/TFC are only at ATC paths, SOLs/IROLs are wherever it is necessary to define reliability
limits. ATC paths are determined primarily by commercial considerations, such as the
interfaces between BAs, and not primarily by reliability limits. If TTC/TFC were reliability in
nature, why would they be confined to only ATC Paths? We operate the entire system reliably
to SOLs, not just the ATC Paths. 3. TTC/TFC can be less than SOLs, but not more. The amount
less is at the discretion of the entity calculating the TTC/TFC. However, if TTC/TFC are reliability
limits, then, IRO-005-3 R10 would require us to operate to the more limiting of the SOL or the
TTC/TFC and we would be artificially constraining the transmission in real time to below the
SOL at the discretion of the entity determining TTC/TFC. This would play havoc in many regions
that do not currently do it this way, such as Florida which operates to SOLs, not TTCs, e.g.,
Florida allows real time actual flows to exceed TTCs, but not SOLs. If TTC is a reliability limit,
then IRO-005-3 R10 would not allow us to continue this process. 4. FAC-011 includes
consideration of a reliability margin in R3; hence, SOLs already include a true reliability margin.
Since TTC/TFC must be less than an SOL, TTC/TFC already includes that reliability margin.
Consequently, TRM is an additional margin for commercial considerations and is not a true
reliability margin. That is, TRM is used to reduce the risk of curtailment post-contingency and is
not a true reliability margin. Hence, it is clear to FMPA that TTC/TFC/TRM are commercial
values, not reliability values. Interpreting them as reliability values is inconsistent with the rest
of the standards and would cause harm to markets by artificially constraining real time
operations. Since they are commercial values, FMPA believes that the TSP is the appropriate
function to calculate these values and not the TOP. That is, the TOP determines actual
reliability limits - SOLs and IROLs, then the TSP determines TTC/TFC/TRM based on the TOPs
SOL calculations with discretion based on commercial considerations such as limiting risk of
curtailment. And, as such, the determination of these commercial values can eventually be
moved to NAESB business practice standards when NAESB is ready to develop such standards;
however, such a transition is unlikely if the standard continues to be assigned to TOPs. In
addition, the FERC Pro Forma OATT is clear that it is the Transmission Providers’ responsibility
to develop these TTC, ATC, CBM, and TRM methodologies. See Attachment C of the Pro Forma.
Below quotes the FERC’s Pro Forma OATT as posted on the FERC site: At 3(A): “For TTC, a
Transmission Provider shall: (i) explain its definition of TTC; (ii) explain its TTC calculation
methodology; (iii) list the databases used in its TTC assessments; and (iv) explain the
assumptions used in its TTC assessments regarding load levels, generation dispatch, and
modeling of planned and contingency outages.” Within Attachment C, the Pro Forma similarly
requires the Transmission Provider to explain ATC/AFC, TRM and CBM (and ETC). Hence, the
standard as proposed is duplicative of other regulatory requirements. NAESB is the entity that

develops business practices to support the FERC Pro Froma OATT, and as such, they should be
the entity that develops any standards related to TTC/TFC, ATC/AFC, CBM and TRM, not NERC.
If TTC/TFC and TRM are left as the responsibility of the TOP, then there is a danger of the TOP
and TSP each developing methodologies (TOP in accordance with NERC, TSP in accordance with
the Pro Forma OATT) that contradict with each other. Bear in mind that there are cases where
the TOP and TSP are not vertically integrated. How would such a conflict be resolved? FMPA
understands that there may be regional differences that may call for regional variances (e.g.,
WECC); however, the standards are written around the SOL reliability construct with TTC/TFC
being commercial in nature.
Individual
Catherine Wesley
PJM Interconnection
PJM supports the SRC’s response to this question specific to their comment recommending
consistency in the Purpose statement for use of the terms “available transmission system
transfer capability” and “available transmission system capability”.
PJM supports the MOD A project overall. It appreciates the effort to consolidate the applicable
MOD standards into one standard with focus on what is required for reliability.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
Agree
SERC PSS
Group
Southern Company: Southern Company Services, Inc; Alabama Power Company; Georgia Power
Company; Gulf Power Company; Mississippi Power Company; Southern Company Generation;
Southern Company Generation and Energy Marketing
Pamela Hunter
1) Comments: General Comments a. Bulk-Power system (BPS) – BPS in not a defined acronym
and should to be taken out of standard b. Transmission Operator – has an acronym TOP and
should be used throughout the standard or acronym’s should be taken out and not used. c.
Transmission Services Provider – has an acronym TSP and should be used throughout the
standard or acronym’s should be taken out and not used. d. There are several other terms that
need acronyms (Planning Coordinator, Reliability Coordinator, etc.) or acronym’s should be
taken out and not used. 2) Specific Standard Comments a. Purpose – The term “other” in the
last sentence refers to what? If you mean other planners and operators then need to qualify
that planners are Transmission Services Providers and operators are Transmission Operators.
There is a disconnect between the two in this last sentence. b. We appreciate the clarity SDT
provided for R1.1 by the language in M1. Since the entities are audited based on the
requirement rather than the measure, R1.1 should be edited to reflect the intent. 1.1 Each
methodology shall describe the method used to account for the following limitations, which

are applicable in both the pre- and post-contingency state: • Facility ratings; • System voltage
limits; • Transient stability limits; • Voltage stability limits; and • Other System Operating Limits
(SOLs). c. M1 – There is an inconsistency between the bullets and R1. i. Third bullet states “A
copy of the request and a description of the method used to perform the impact test (1.3.1) or
account for the requested constraints (1.3.2)” should include 1.3.3 in the measurement such as
“A copy of the request and a description of the method used to perform the impact test (1.3.1)
or account for the requested constraints (1.3.2 and 1.3.3)”. d. R3 rationale – term “LoadServing Entities (LSEs), who’s Loads” should be “Load-Serving Entities (LSEs), whose Loads” e.
R3 – The term “determines” should be change to “maintains”. The TSP does not determine the
CBM but acts upon and maintains the CBM request from the LSE. The RP studies and
determines the amount of CBM that can be reliably justified the TSP does not run these
studies. f. M3 - The term “determines” should be change to “maintains” to be consistent with
R3.
Group
Seattle City Light
paul haase
Agree
Snohomish PUD

Consideration of
Comments Summary
Project 2012-05 ATC Revisions (MOD A)
December 11, 2013 

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1 of 14 

Table of Contents
Table of Contents ...................................................................................................................................................... 2 
Introduction ........................................................................................................................................................... 4 
Independent Experts Review Panel Recommendations ........................................................................................ 4 
Purpose Section ..................................................................................................................................................... 4 
Requirement R1 ..................................................................................................................................................... 5 
Measure M1 ....................................................................................................................................................... 7 
Requirement R2 ..................................................................................................................................................... 7 
Measure M2 ....................................................................................................................................................... 9 
Requirement R3 ..................................................................................................................................................... 9 
Measure M3 and M4 ........................................................................................................................................ 10 
Requirement R4 ................................................................................................................................................... 10 
Requirements R5 and R6 ..................................................................................................................................... 10 
MOD‐001‐2 Compliance Section Comments ....................................................................................................... 12 
Violation Severity Levels (VSLs) ........................................................................................................................ 12 
Compliance ....................................................................................................................................................... 13 
Draft Reliability Standard Audit Worksheet (RSAW) and Compliance Input ....................................................... 13 
General Comments .............................................................................................................................................. 13 

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2 of 14 

Consideration of Comments
Project 2012-05 ATC Revisions (MOD A)
Comment Form
Combined Question 1 and Question 2 Summaries

The Project 2012‐05 ATC Revisions Drafting Team thanks everyone who submitted comments on the MOD‐001‐2 
standard. The standard was posted for a 45‐day public comment period from October 4, 2013 through November 
20, 2013. Stakeholders were asked to provide feedback on the standard and associated documents through a 
special electronic comment form. There were 28 sets of responses, including comments from approximately 114 
people from approximately 76 companies, representing nine of the 10 Industry Segments. 

All comments submitted may be reviewed in their original format on the standard’s project page. 

If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give every 
comment serious consideration in this process. If you feel there has been an error or omission, please contact Vice 
President and Director of Standards Mark Lauby at 404‐446‐2560 or [email protected]. There is also a NERC 
Reliability Standards Appeals Process.1 

1 The appeals process is in the Standard Processes Manual: 

http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf 
NERC | Consideration of Comments Summary – Project 2012‐05 ATC Revisions (MOD A) | December 11, 2013 
3 of 14 

Introduction
The standard drafting team (SDT) appreciates industry comments on the second posting of the MOD A draft MOD‐
001‐2 and associated documents.  

Independent Experts Review Panel Recommendations
Northeast Power Coordinating Council (NPCC) and Independent Electric System Operator (IESO) commented that 
the  requirement  for  developing  a  written  methodology  (or  methodologies)  for  determining  Total  Flowgate 
Capability (TFC) or Total Transfer Capability (TTC) (as per Requirement R1) should be moved to a FAC standard 
(e.g., FAC‐013), if not already adequately covered by a related FAC standard. Also, NPCC and IESO stated there is 
some degree of overlap between Requirement R1 of MOD‐001‐2 and the FAC standards. The SDT does not view 
moving the requirement to the FAC standards as within the scope of the project. The primary focus of this SDT is 
to address outstanding FERC directives. NERC noted that the Independent Expert’s Review Panel recommended 
modifications to the grouping of certain Reliability Standards. When these recommendations are considered for 
implementation, the movement of Requirement R1 to a FAC standard may also be considered by a future drafting 
team.  

Additionally,  the  SDT  concluded  that  there  is  no  overlap  between  the  proposed  Requirement  R1  and  the  FAC 
standards. The FAC standards address facility ratings and System Operating Limits (SOLs) (among other items), 
which  are  utilized  in  Requirement  R1  to  develop  the  TFC  or  TTC.  Further,  while  FAC‐013‐2  addresses  transfer 
capability in the planning horizon, it does not develop a TFC or TTC for the operating horizon—as is the case in 
MOD‐001‐2,  Requirement R1. There are no FAC standards that  address the  development of TFC or  TTC in the 
operating horizon or for use in the determination of AFC or ATC.  

Purpose Section
MRO NERC Standards Review Forum (MRO NSRF), Southwest Power Pool Standards Review Group (SPP SRG), and 
Southern  Company  commented  that  the  term  “Bulk‐Power  System”  should  be  replaced  with  “Bulk  Electric 
System,” because Bulk‐Power System is not defined. The SDT chose to keep the term “Bulk‐Power System,” which 
is now a defined term in the NERC Glossary. As approved by FERC on July 9, 2013, Bulk‐Power System is defined 
as:  

(A)  facilities  and  control  systems  necessary  for  operating  an  interconnected  electric  energy 
transmission network (or any portion thereof); and (B) electric energy from generation facilities 
needed to maintain transmission system reliability. The term does not include facilities used in 
the local distribution of electric energy.2  

MRO NRSF also commented that use of the term “Bulk Electric System” would “pull in any <100 kV systems that 
MOD‐001‐2  would  be  applicable  too.”  The  SDT  noted,  however,  that  use  of  the  term  “Bulk‐Power  System”  is 
appropriate for the purpose statement of the standard as it does not specifically exclude or include systems based 
on voltage level alone.  

Independent System Operator/Regional Transmission Organization Standards Review Committee (ISO/RTO SRC), 
IESO,  and  NPCC  commented  that  the  first  sentence  of  the  purpose  statement  clearly  conveys  the  reliability 
purpose of the standards, meaning that the proposed second sentence is unnecessary and creates confusion as 
to the intent of the standard. The SDT agreed with this comment and deleted the second sentence in its entirety. 
The  removal  of  the  second  sentence  also  addresses  the  commenters’  (including  Manitoba  Hydro’s)  concern 
regarding the use of the inconsistent phrases “available transmission system transfer capability” and “available 
transmission system capability.” To be consistent with the title of proposed MOD‐001‐2, the word “transfer” was 

2
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deleted  from  the  first  sentence  of  the  purpose  statement.  Southern  Company  also  commented  on  the  use  of 
“other” in the second sentence, which was deleted.  

Requirement R1
Florida Reliability Coordinating Council, Inc. (FRCC) provided verbal comments to the SDT about adding a clarifying 
statement  in  the  rationale  for  Requirement  R1  with  regard  to  whether  a  Transmission  Operator  (TOP)  must 
determine TFC or TTC. To address this concern, the SDT added the following statement at the end of the Rationale: 
“Requirement R1 sets requirements for the determination of TFC or TTC, but does not establish if a TOP must 
determine TFC or TTC.” The SDT noted that the RSAW will also contain this information. 

Kansas City Power & Light (KCPL) stated that the term “determining” is the actual act of calculating, and because 
some registered entities do not make these calculations, those registered entities would not need a methodology. 
The  SDT  disagrees  with  KCPL  on  the  use  of  “determining”  as  a  synonym  for  calculating.  The  terms  calculate, 
establish, decide, maintain, use, develop, provide, produce, determine, find, and more were reviewed. The SDT 
selected “determine” as the  best fit to capture both  the situations where a  true calculation is  performed and 
others where a limit that was calculated elsewhere is used. No one word was suggested that was above criticism. 
“Determine” was selected not as the perfect word, but the best fit within the English language. Regardless of the 
term  or  phrase  used,  this  test  of  whether  the  requirement  applies  is  relatively  simple:  If  the  TOP  has  a  value 
labeled TFC or TTC that it uses for any purpose or passes on to another entity, it has determined a TFC or TTC 
regardless of how that value was determined. The SDT does agree with KCPL that if an entity does not determine 
a TFC or TTC, then the requirement does not apply.  

SPP SRG commented that the Rationale section should be modified to capitalize “real‐time.” The SDT made this 
change throughout the standard.  

American  Electric  Power  (AEP),  Florida  Municipal  Power  Agency  (FMPA),  and  Oklahoma  Gas  &  Electric  (OGE) 
commented that (1) the responsible entity under Requirements R1 and R4 should be the Transmission Service 
Provider (TSP)—not the TOP—and (2) the TOP applicability should be removed from Requirements R5 and R6. As 
discussed in more detail in the Consideration of Comments Summary posted with the second draft of the standard 
on October 4, 2013,3 Requirements R1 and R4 correctly apply to TOPs that determine TTC, TFC or Transmission 
Reliability Margin (TRM) values. The SDT understands that there are different practices across the continent as to 
which entity (i.e., TSP or TOP) determines TFC or TTC. The standard is drafted in a manner to support these varying 
practices. The current draft RSAW contains further language that elaborates on this point to alleviate compliance 
concerns in some of the scenarios in which a TSP performs the TTC or TFC calculations without a Coordinated 
Functional Registration with the member TOP.  

AEP also stated that should TOPs remain as the Responsible Entity under Requirement R1, and the SDT should 
consider changing “Total Transfer Capability” to “Total Transfer.” Because the term “Total Transfer” is not defined 
within  the  NERC  Glossary,  the  SDT  retained  the  defined  term  “Total  Transfer  Capability.”  The  NERC  Glossary 
definition for Total Transfer Capability provides TOPs latitude in developing methods to determine TTC values for 
its system. 

Arizona Public Service (APS) commented that Requirement R1, part 3.1 implies that (1) the constraints that are 
requested  by another TOP need  to  be  included, and (2)  it is not  clear if the constraints apply only to thermal 
constraints or if it also applies to other constraints, such as voltage. The requirement is not limited to thermal 
constraints. The language of Requirement R3, part 3.1 is intended to cover any type of constraint that is requested 

3

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to be included. The SDT noted that Requirement R3, part 3.3 allows TOPs flexibility to agree on a process for how 
to determine whether a requested constraint needs to be included. The SDT chose to provide industry with this 
flexibility in recognition of the fact that industry previously applied proxy Flowgates for the purpose of including 
voltage‐stability  limits.  Further,  various  studies  that  involve  maximum  stability‐related  flows  and  calculated 
transfer distribution factors indirectly serve to include consideration of such “other constraints.” 

ISO/RTO SRC asked whether there is a definition in the Glossary for the phrase “pre‐ and post‐contingency state” 
and if the TOP is to define the post‐contingency state. There is no NERC definition for the phrase “pre‐ and post‐
contingency state.” However, the term “Contingency” is defined as “The unexpected failure or outage of a system 
component,  such  as  a  generator,  transmission  line,  circuit  breaker,  switch  or  other  electrical  element.”  In 
response, the SDT noted that the TOP must define the post‐contingency state.  

ISO/RTO  SRC  also  questioned  whether  Requirement  R1,  parts  1.2.1  and  1.2.5  are  applicable  to  TFC.  The  SDT 
responds that the language in Requirement R1, part 1.2 allows the TOP to designate which elements are parts of 
their calculation of TFC. Requirement R1, part 1.2 does not require an entity to use all of the items; but requires 
only that the entity describe the elements it uses. Part 1.2 also includes Flowgate users who do, at times, find 
those elements are included in their TFC determination; therefore, specifically excluding those elements would 
not be appropriate.  

Manitoba Hydro commented that Requirement R1, part 1.3 would be more accurate if the opening line said: “The 
process  for  determining  whether  to  include  any  reliability  related  constraints,”  as  opposed  to  “including  any 
reliability related constraints,” because it may be determined that the constraints are not be included. In response, 
the SDT noted that this change would make the requirement optional and weaken the reliability intent. Therefore, 
the  SDT  did  not  make  any  changes  to  adding  language,  but  did  hyphenate  “reliability‐related”  for  consistency 
purposes within the proposed standard. 

Manitoba Hydro also commented that in Requirement R1, part 1.3.2 the words “in its methodology” are missing 
after  the  word  “describe.”  For  consistency  purposes  within  the  proposed  standard,  the  SDT  agreed  with  the 
comment and added the missing language.  

ACES suggested that the SDT delete Requirement R1, parts 1.1.1 through 1.1.4 because they are SOLs. While this 
was discussed extensively on several occasions, the SDT ultimately found the term SOL was not applied enough 
universally to be used alone in part 1.1. The SDT included the elements that generally go into determining an SOL, 
and added the term “other” to the last item in part 1.1.5 to include SOLs developed by a limit other than those 
listed in parts 1.1.1 through 1.1.4. 

ACES questioned Requirement R1, part 1.3, asking who determines the proper constraints from a requesting TOP. 
The SDT responds that Requirement R1, part 1.3 and its sub‐parts are specific that the requesting TOP makes the 
request and the TOP doing the calculation must honor it. ACES also asked what would happen if the constraints 
did not apply. The SDT responds that the testing methodology described in Requirement R1, parts 1.3.1, 1.3.2, or 
negotiated between entities in part 1.3.3 will ensure that only those constraints that are applicable to the path 
under study will have influence. ACES then asked, “How is it possible that one TOP has authority over another 
TOP?” The SDT responds that Requirement R1, part 1.3 makes it clear that one TOP can request another TOP to 
honor  its  reliability  constraints.  There  is  nothing  that  precludes  discussion  between  the  entities  and  the 
modification or withdrawal of a request, but—as a reliability guide—if one TOP asks another TOP to honor their 
reliability‐based constraints, they ultimately must be honored. 

ISO/RTO  SRC  questioned  why  “planned  outages”  is  used  instead  of  “forced  outages”  or  “known  outages”  in 
Requirements R1 and R2. The SDT responded that the determination of AFC, ATC, TFC, or TTC are future‐looking 
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values. The phrase “planned outages” is used to account for the outages that the TOP or TSP is planning to account 
for in their determination. This is similar to the TOP doing operational studies and having outages to plan around.  
Whether that outage was voluntary or a forced, it is still within the studying and planning horizon. The phrase 
“planned outage” includes forced outages that need to be planned for. The SDT discussed using “known outages” 
but preferred “planned outages.” The phrase “planned outages” can be defined by the team. For example, if the 
Region has an outage‐reporting system, then a planned outage may be any outage within that system that feeds 
the  automated  TFC,  TTC,  AFC,  or  ATC  calculation.  The  phrase  “known  outage”  would  not  allow  that  type  of 
clarification.  

Measure M1
NPCC, IESO, and ISO/RTO SRC stated that the last bullet in Measure M1 is written as a requirement, not a measure. 
In response, the SDT modified the Measure. The new Measure reads, “Evidence that currently active TFC or TTC 
values were calculated based on the current methodology.” NPCC further stated that Requirement R1 does not 
require  a  TOP  to  use  its  own  methodology.  The  SDT  stated  that  NPCC  is  correct  in  the  technical  sense  that 
Requirement R1 does not require TOP to follow their methodology, but it does require the methodology to reflect 
their process. The changes the SDT made to Measure M1 should reflect this.  

ACES, SERC Planning Standards Subcommittee (SERC PSS), and Manitoba Hydro commented that the approach in 
Requirement  R1,  part  1.3.3  is  reasonable,  but  it  is  not  clear  on  what  evidence  needs  to  be  maintained.  The 
commenters asked that the drafting team provide a measure for this part. ACES suggested that evidence could 
include emails, attestations, meeting minutes, or other agreements between the TOPs. In response to this and its 
own review, the SDT changed the measure to solely reference that a description of the process is necessary within 
the ATCID and removed any reference to further evidence. The SDT noted the final paragraph of the measure 
regarding demonstration that the methodology was followed is the appropriate place to include language about 
receiving a request and following the process. The SDT chose not to call out this language explicitly, however, 
because verification to the level of tracing a request all the way through the methodology is not necessary on 
every occasion to measure compliance with the requirement. 

ISO/RTO SRC commented that one or more of the sub‐bullets under the first bullet do not apply to their method 
of  determining  AFC  and  requested  clarifying  language.  The  SDT  responded  that  the  parent  bullet  reads  that 
“methods of accounting for these limits may be included, but are not limited to, one or more of the following,” 
which allows for only one method or even a different method to be used. The measure does not require that each 
of  the  sub‐bullets  be  used.  ISO/RTO  SRC  also  commented  on  the  bullet  that  reads,  “A  statement  that  the 
monitoring of a select limit(s) results in the TFC or TTC not exceeding another set of limits.” This bullet was added 
to clarify that in the determination of TFC or TTC it is not necessary to simulate or calculate every conceivable limit 
in detail (e.g., example often limiting operations to within facility ratings is sufficiently restrictive that stability and 
voltage  limits  are  not  reached).  The  bullet  clarifies  that  the  monitoring  of  the  more  restrictive  set  of  limits  is 
sufficient and the outer limits do not have to be explicitly monitored.  

Requirement R2
FRCC provided verbal comments to the SDT questioning whether a TSP must determine AFC or ATC. Therefore, 
the SDT added “Requirement R2 sets requirements for the determination of AFC or ATC, but does not establish if 
a TSP must determine AFC or ATC” to the end of the Rationale for R2. 

NPCC and IESO stated they agree with the Independent Experts’ recommendations to remove the requirements 
for  developing  an  AFCID  or  ATCID  and  request  NAESB  adopt  or  develop  these  requirements  in  their  business 
practices. The commenters stated the implementation documents are intended for calculating the AFCs or ATCs 
for  business  usage  and  do  not  contribute  to  ensuring  BES  reliability.  The  commenters  suggest  removing 
Requirement R2 from the proposed standard. In response, the SDT stated that, as described in the purpose and 
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rationale,  the  value  of  AFC  or  ATC  affects  the  services  offered  to  the  market  and,  when  those  services  are 
purchased, they affect the BPS as seen by TOPs, TSPs, and others. As such, TOPs, TSPs, and other entities having 
access to accurate information regarding how AFC or ATC is determined, along with the constituent values, is a 
reliability need that is protected by Requirement R2. For Flowgate users, Requirement R2 goes further and ensures 
that overrides are used when available to minimize the chance of oversubscription on a Flowgate.  

Manitoba Hydro suggested changing the word “that” in Requirement R2, part 2.1 to “provided such elements.” 
The SDT made the change, which is consistent with the language in Requirement R1, part 1.2.  

Manitoba Hydro questioned whether Requirement R2.2 implies that a TSP should identify reliability constraints 
using Requirement R1, part 1.3. In response, the SDT noted that Requirement R2, part 2.2 is specific to those TSPs 
that utilize the Available Flowgate Methodology. This requirement specifies that a TSP that utilizes a neighboring 
TSP’s Flowgate in the determination of AFC shall use the neighboring TSP’s calculated AFC values.  

APS commented that it is unclear what needs to be included in the ATCID to comply with Requirement R2, part 
2.1.3.  In  response,  the  SDT  noted  the  existing  phrase  “transmission  uses”  requires  the  TSP  to  include  Existing 
Transmission  Commitments  (ETC)  as  applicable  to  the  respective  Firm  or  Non‐Firm  ATC  calculation  without 
specifically calling out all the various types of transmission system use that can be included in ETC. NAESB may 
consider including in its standards any additional details to further clarify the handling of “transmission uses.”  

APS also commented that it is not clear why there are separate documents required for an entity’s ATC, CBM, and 
TRM. APS stated that CBM and TRM should reside within an entity’s ATCID. In response, the SDT noted that ATC, 
CBM,  and  TRM  implementation  documents  are  applicable  to  different  functional  entities  and  serve  different 
purposes, and therefore should be separate. However, the standard does not preclude an entity from combining 
them into a single document.  

ACES commented that Requirement R2 should reflect that once TTC or TFC is complete per Requirement R1, then 
determining AFC or ATC could be a simple algebraic calculation. ACES stated that the requirement as written, in 
parts 2.1.1 through 2.1.7, implies another Load flow study must be performed to calculate AFC or ATC, which may 
not be necessary. In response, the SDT clarified that the exact method for determining ATC must be defined in the 
TSP’s  Implementation  Documents  and  stated  that  the  standard  does  not  preclude  the  use  of  an  algebraic 
calculation. Some entities use a simple algebraic calculation for the conversion of TTC to ATC; however, other TSPs 
may wish to use an additional Load flow study to aid in the determination of ATC from AFC. The requirement retains 
that flexibility. 

ISO/RTO  SRC  commented  that  “for  reliability  constraints”  should  be  modified  to  read  “for  reliability‐related 
constraints.” The SDT agreed and made the clarifying change. 

Georgia Transmission Corporation (GTC) suggested that Requirement R2 should just say “If a TSP determines ATC, 
then…”  with  a  requirement  part  regarding  having  an  ATCID  and  a  requirement  part  regarding  following  the 
established ATCID. The SDT worked with the GTC representative on the SDT to draft a conforming requirement, 
but ultimately decided that the requirement as currently written is sufficiently clear. The requirement establishes 
when an ATCID is required (if ATC values are determined) and that the ATCID must reflect the current process. 
Stating  that  the  entity must follow  their ATCID or  that their ATCID must reflect its process reaches  the  same 
destination—an accurate ATCID with a conforming process.  

Tennessee Valley Authority (TVA) provided general commentary that the revised standard was too general. The 
SDT discussed this; however, because it allows for greater flexibility in approaches for addressing new techniques 

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in  calculation,  new  tools,  and  new  challenges  on  the  BPS,  the  SDT  asserts  that  the  revised  standard  protects 
reliability to the same or higher level than the existing standard.   

TVA  provided  a  specific  criticism  that  the  Requirement  R2,  part  2.2  punishes  Flowgate  methodology  users  by 
requiring they use the AFC determined by the TSP that is responsible for the constraint. The SDT responds that 
this  requirement  part  was  included  in  the  standard  at  the  request  of  Flowgate  methodology  users.  The 
requirement part is specific only to the Flowgate methodology because there is no similar concept in the TTC‐
based  methodologies.  TVA  further  requested  that  the  requirement  clarify  that  if  the  TSP  responsible  for  the 
constraint does not provide a value, then they should not be required to be use a value. The SDT, including the 
Flowgate methodology users on the team, discussed this at length and concluded that the current Requirement 
R2, part 2.2 is sufficient. From the perspective of the TSP applying part 2.2, if they have not received an AFC value 
from the owner of the constraint, then the owner has not determined one, meaning the TSP is free to handle the 
constraint per their own methodology.  

Measure M2
Manitoba Hydro commented that the last bullet of Measure M2 is about measuring whether or not the TSP is 
using its current method. It would be more closely aligned with the requirement itself if this bullet was phrased in 
a way that referred to the methodology being reflective of the current method. In response, similar to the changes 
for Measure M1, the bullet was modified to address this comment. The SDT revised the Measure while keeping 
the intent intact. The structure of Measure M2 is similar to Measure M1. 

Requirement R3
Southern Company commented that the Rationale had a grammatical error. The SDT corrected the error, replacing 
“who’s” with “whose.” 

SERC  Planning  Standards  Subcommittee  commented  that  the  word  “determined”  should  be  replaced  with 
“maintained” in Requirements R3 and R4. Further, GTC suggested changing “determined” to “established.” The 
SDT  discussed  the  appropriate  wording  in  these  Requirements  and  concluded  that  “determined”  is  most 
appropriate and should be used throughout the requirements. “Determine” was selected over “establish” because 
the team stated “establish” implies that it is the first time a value is set up. “Maintain” was not selected because 
it implies that the entity takes some sort of action to keep that value in place. “Determine” accurately describes 
the process for setting this value (i.e., the entity reviews the information available to it and either selects a value 
directly or makes a series of calculations to set the value, thereby, determining the value). For consistency, all 
instances  of  “establish,”  “establishes,”  or  “established”  were  modified  to  “determine,”  “determines,”  or 
“determined” respectively.  

NPCC and IESO commented that Requirement R3 does not require a TSP to determine CBM Values, only to have 
a CBMID that describes its method if it does so. NPCC and IESO state the measure exceeds the requirement by 
obligating the TSP to determine CBM Values. The SDT agrees that Requirement R3 does not require a TSP to 
determine  CBM  values  and  only  requires  those  TSPs  that  determine  CBM  to  have  a  CBMID  and  follow  the 
methodology  in  that  CBMID.  Because  Requirement  R3  is  only  invoked  if  the  TSP  determines  CBM  values  and 
requires that the CBMID reflect the TSP’s current practices, the measure appropriately expects a demonstration 
that the CBM values were determined per the CBMID. This demonstration is necessary to validate that the CBMID 
reflects the TSP current practices, as stated in the requirement. NPCC and IESO suggest removing the requirement 
and remanding it to NAESB because it is solely a business practice. The SDT agrees that the choice and method 
of determining CBM is a business practice outside the scope of NERC’s standards; however, if CBM is determined, 
it  does  affect  AFC  and  ATC  values.  Therefore,  mandatory  disclosure  of  an  accurate  description  of  the  TSP’s 
practice to other entities is a reliability issue.   

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GTC suggested that the second sentence in Requirements R3 and R4 be modified to state that the entity must 
develop values based on its methodology. The SDT replied that the purpose of the standard is not to ensure that 
an entity can write a methodology and follow it, but instead to ensure that an entity has a methodology that 
accurately reflects its process and can be shared with others.  

Measure M3 and M4
For consistency with the requirement, Manitoba Hydro suggested changing Measure M3 to refer only to TSPs that 
determine CBM. In response and based on comments to the initial posting of the standard (July 11, 2013 to August 
27, 2013), the SDT modified Measure M3 to include examples of evidence that entities that do not determine 
CBM may provide to demonstrate compliance with the requirement. The SDT noted that it is important for the 
Measure  to  contain  various  ways  in  which  entities  may  comply  with  the  requirement  based  on  particular 
circumstances. 

SERC PSS and ACES suggested changing “affidavit” to “attestation” in Measures M3 and M4. The SDT made this 
clarifying change as an attestation is the appropriate evidence, consistent with Compliance Application Notice 
(CAN)‐0030.  Attestations  may  be  provided  to  Compliance  Enforcement  Authorities  (CEAs)  to  demonstrate 
compliance where other forms of evidence are not available.  

Requirement R4
Similar to their comments on Requirement R3, NPCC and IESO stated that Requirement R4 does not require a TOP 
to determine TRM Values; it only requires the TOP to have a TRMID that describes the method it uses, if it has 
one.  NPCC  and  IESO  also  voiced  that  the  measure  exceeds  the  requirement  by  obligating  the  TOP  to  show 
determined TRM values. The SDT agrees with NPCC and IESO that Requirement R4 does not require a TOP to 
determine TRM values but only requires that the TOP have a TRMID and to follow the methodology in the TRMID. 
Because Requirement R4 is only invoked if the TOP determines TRM values and requires that the TRMID reflect 
their practices, the measure appropriately expects a demonstration that the TRM values were determined per the 
TRMID. This demonstration is necessary to validate that the TRMID reflects the TOP’s current practices, as stated 
in the requirement. NPCC and IESO also suggest removing the requirement and remanding it to NAESB. The SDT 
agrees  that  the  choice  and  method  of  determining  TRM  is  a  business  practice  outside  the  scope  of  NERC’s 
standards; however, if TRM is determined, it does affect AFC and ATC values, making mandatory disclosure of an 
accurate description of the TOP’s practice to other entities a reliability issue.  

GTC  commented  that,  similar  to  previous  requirements,  the  language  needs  to  be  consistent  within  the 
requirement.  The  SDT  modified  the  requirement  to  change  all  instances  of  “establish”  to  “determine”  for 
consistency purposes.  

Requirements R5 and R6
The SDT received numerous comments on Requirements R5 and R6. In particular, APS and IESO recommended 
the merging of the two requirements. To varying degrees, ACES, NPCC, IESO, and ISO/RTO SRC questioned the 
reliability need for the requirements and the clarity of having two entities responsible for the same requirement. 
The SDT concluded that because Requirements R5 and R6 serve two distinct reliability needs, they should remain 
as separate requirements in the standard. The SDT also concluded that the requirements are sufficiently clear as 
to the responsibilities of TSPs and TOPs.   

Requirements R1, R2, R3, and R4 require documentation of the methods for developing their respective ATC/AFC, 
TTC/TFC, CBM, and TRM values; however, the requirements do not require the disclosure of those methods to 
other functional entities that need to understand those methodologies for reliability purposes. Requirements R5 
and R6 provide this mechanism. A fundamental principle underlying this standard is that because AFC and ATC 
values measure available transmission capacity to be sold to the market, there are reliability implications when 
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that capacity is sold and used. The values do not solely impact the TSP that posts the AFC or ATC value and sells 
the service, but it affects TOPs, RCs, and other TSPs. The amount of transmission that is available and sold impacts 
the manner in which operators and planners of the grid carry out their job functions. As such, it is important for 
these entities to understand the methodologies for determining ATC/AFC and have access to the data underlying 
those values.  

While  Requirement  R5  addresses  disclosure  of  methods,  Requirement  R6  addresses  forward‐looking  data  to 
support a neighboring entities’ calculation. Requirement R5 allows any entity with a demonstrated reliability need 
to obtain the methodologies and see clarification of any element contained in those methodologies. Requirement 
R6 allows TOPs and TSP to obtain system data from other TOPs and TSPs. As stated in Requirement R6, if an entity 
has data it used to determine AFC, ATC, TFC, or TTC and another TOP or TSP requests access to that data for use 
in their own determination of those values, then the data must be provided. Requirement R6 is necessary for 
reliability  because,  without  this  requirement,  a  neighboring  entity  can  be  forced  to  estimate  a  value  (e.g.,  a 
neighboring system’s Load forecast) rather than use that entity’s own Load forecast.   

Requirements R5 and R6 are very specific in how they are invoked; that is, through a written request that cites 
the requirement. This written request for information or system data was included to lower the administrative 
burden for most entities.  

In  response  to  comments  from  NPCC,  IESO,  and  ISO/RTO  SRC  that  the  requirements  could  be  subject  to 
interpretation because they list the TOP and the TSP as responsible entities, the SDT stated that it does not believe 
the language in the standard is unclear with respect to each entity’s obligation. An entity that receives a request 
for its methodology, a clarification, or its data can only provide the requested material if it is the functional entity 
with that material. For instance, should a TOP receive a request to clarify an element of ATCID, the TOP should 
respond that it does not calculate ATC and therefore can provide no further insight.  

Manitoba Hydro asked for clarity on the phrase “demonstrating a reliability need” and how it should be assessed. 
The SDT noted that there are other FERC‐approved NERC Reliability Standards that use the phrase “reliability‐
based need” or “reliability need.” For clarification, a Planning Coordinator (PC), Reliability Coordinator (RC), TOP, 
TSP,  or  Transmission  Planner  (TP)  would  not  need  to  demonstrate  a  reliability  need  under  the  standard.  That 
qualification only applies to other functional entities. Lastly, the TOP and TSP would be the entities to determine 
if a requestor has demonstrated a reliability need.  

SPP  SRG  made  several  grammatical  suggestions  to  the  Rationale  for  Requirement  R6.  The  SDT  reviewed  the 
language and made several grammatical edits (e.g., “TOP and TSP” to “TOP or TSP” and “are” to “is”).  
Manitoba Hydro commented that there is no guidance given as to the meaning of “on an ongoing basis.” Manitoba 
Hydro suggested that the word “beginning” be added before “on an ongoing basis.” By the phrase “on an ongoing 
basis,” the SDT is referring to data such as Load forecasts or expected interchange that would be provided on an 
hourly, daily, or other ongoing incremental basis.  

Manitoba Hydro also commented that “at regular intervals” was removed from the requirement, but remained in 
the measure. The SDT deleted “at regular intervals” from the measure.  

Manitoba  Hydro  commented  the  punctuation  in  Measure  M5  results  in  the  measure  not  matching  the 
requirement.  Manitoba  Hydro  commented  that  the  measure  should  be  rewritten  as  follows:  “Examples  of 
evidence include, but are not limited to, dated records of the request from a Planning Coordinator, Reliability 
Coordinator, Transmission Operator, Transmission Planner, Transmission Service Provider, or another registered 
entity who demonstrates a reliability need, and the Transmission Service Provider’s response to the request, or if 
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no requests have been received, a statement by the Transmission Service Provider that they have received no 
requests.” The SDT stated that the measure is clear in what the examples of evidence are for any request and has 
not made any changes to the measure to be explicit as to who the request is coming from. 

MOD-001-2 Compliance Section Comments

Violation Severity Levels (VSLs)
ISO/RTO SRC suggested that the following be moved from a High VSL to Moderate: “Each Transmission Operator 
that determines TFC or TTC has not used (i) an impact test process for including requested constraints, (ii) a process 
to account for requested constraints that have a five percent or greater distribution factor for a transfer between 
areas  in  the  TTC  determination,  or  (iii)  a  mutually  agreed  upon  method  for  determining  whether  requested 
constraints need to be included in the TFC or TTC determination. (1.3.1, 1.3.2, 1.3.3)” for Requirement R1. The 
SDT noted that the designation of this VSL is appropriate as it does not meet the majority of the intent of the 
requirement, but does meet some of the intent.  

Manitoba Hydro commented that including “any” in the VSL for Requirement R1 could be interpreted to mean 
“any one of.” In response, the SDT noted that the VSL is gradated; from not including one limitation, not including 
two  limitations,  or  not  including  any  limitations.  The  VSL  maps  to  those  entities  that  do  have  a  TTC  or  TFC 
methodology, but no limitations are included.  

ISO/RTO SRC suggested moving Requirement R2’s VSL from High to Low because the TSP is still calculating AFCs. 
In response, the SDT noted that it is under the impression the commenter is referring to those entities determining 
AFC or ATC not following its current practices. The VSL is mirrored to follow the existing FERC approved VSL for 
MOD‐001‐1a calling for the entity to keep the document current. The SDT noted that the VSL is appropriate. 

Manitoba Hydro commented that the VSLs for Requirements R3 and R4 are not consistent with the language in 
the requirements. The VSLs contain language for entities that “use” CBM or TRM, while the requirements contain 
language for entities that “determine” CBM or TRM. Therefore, the SDT revised the VSLs to match the language 
in the requirements and measures (i.e., determine). 

Manitoba  Hydro  commented  that  the  VSLs  for  Requirement  R5  do  not  exactly  correlate  to  the  language  in 
Requirement R5. The language in the requirement reads that the TOP or TSP must respond to a written request 
in writing, while the VSL does not specify that it must be in writing. To mirror the language and increase the clarity, 
the SDT added “in writing” after “respond” to the VSLs within Requirement R5.  

ACES  commented  that  the  term  “current”  could  potentially  result  in  negative  impacts  for  enforcement.  ACES 
stated that it appeared as if an entity is not including one limitation in its methodology would result in a lower 
VSL. However, if circumstances changed and the entity were required to add a limitation but it chose not to, then 
its  written  methodology  would  not  be  current,  which  would  result  in  a  severe  violation.  ACES  recommended 
removing the “current” language from the VSLs because it could be misinterpreted. In response, the SDT noted 
no changes were necessary as the VSL mirrors the requirement language and is therefore appropriate.  

TVA  stated  that  the  VSLs  for  Requirements  R3  and  R4  should  not  be  severe.  Per  the  VSL  Guidelines,4  the 
assignment to a severe VSL is appropriate. Because a binary requirement is a “pass or fail” requirement in which 
any  degree  of  noncompliant  performance  results  in  totally  or  mostly  missing  the  reliability  intent  of  the 
requirement, the single VSL must be “Severe.” 

4
 North American Electric Reliability Corp., Order on Violation Severity Levels Proposed by the Electric Reliability Organization, 123 FERC ¶ 
61,284 (2008)(“VSL Order”), order on rehearing and clarification, 125 FERC ¶ 61,212(2008). 
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The SDT responded to GTC stating that the appropriate clarifying changes in the requirements were made in the 
VSLs. 

Compliance
Manitoba Hydro suggested that the SDT modify the language in Compliance Section 1.3 because it refers to “a 
process  found  in  the  NERC  Rules  of  Procedure.”  Manitoba  Hydro  noted  that  it  has  its  own  Compliance  and 
Monitoring program and has only adopted select aspects of the NERC Rules of Procedure. To address Manitoba 
Hydro’s  concern,  the  SDT  deleted  the  reference  to  NERC  Rules  of  Procedure  to  clarify  that  Section  1.3  simply 
provides an explanation  of the term “Compliance  Monitoring and Assessment Processes” and is not  meant  to 
refer to any specific process found in the NERC Rules of Procedure.  

ACES questioned the need for the standard to require a five‐year evidence retention period for implementation 
and methodology documents. ACES stated that the TOP will be audited every three years, meaning five years of 
evidence is unnecessary. The SDT retained the five‐year retention period on implementation and methodology 
documents to line up with the FERC directive on retention (S‐ Ref 102045). The SDT does not believe that this 
retention period presents a significant burden to industry. 

Draft Reliability Standard Audit Worksheet (RSAW) and Compliance
Input
ACES  commented  that  while  the  compliance  input  was  appreciated,  it  would  help  to  have  SDTs  reach  out  to 
compliance during the informal development process and post compliance guidance and a draft RSAW with each 
standard during the initial posting. In response, the SDT noted that it was a milestone to have the RSAW posted 
prior to the second ballot. The SDT understands that the coordination between SDTs and Compliance is an evolving 
process and that this posting of the MOD A draft RSAW was a step in that evolution.  

ACES also commented that there are several statements in the compliance guidance where an auditor will focus 
on  the  most  recent  values  instead  of  historical  evidence  and  that  audit  teams  would  be  looking  forward  to 
ensuring an entity is following its methodology to determine a given value. ACES supports this approach, which is 
consistent with the Reliability Assurance Initiative (RAI). The SDT has considered this comment and agrees with 
ACES.  

General Comments
Southern Company commented that acronyms were used inconsistently within the standard. In the Rationales, 
all  acronyms  are  spelled  out  on  first  use  (the  acronyms  shown  in  parentheses)  and  then  used  as  acronyms 
throughout the remainder of the Rationales. This is because the Rationales  will be moved from the  Reliability 
Standard after the Board of Trustees adoptions. However, within the standard, the functional entities are spelled 
out while other proper nouns, such as Available Transfer Capability, are used as acronyms. This is because the 
requirements are auditable and enforceable and the functional entities are spelled out in the rest of the NERC 
Reliability Standards.  

ReliabilityFirst commented that proposed MOD‐001‐2 lacks any measurement of whether the communication of 
available of transmission service is accurate. ReliabilityFirst believes that the addition of a requirement to verify 
that  past  communications  of  service  availability  were  accurate  would  be  an  improvement.  For  consideration, 
ReliabilityFirst  recommends  a  requirement  for  periodic  analysis  of  the  communication  of  transmission  service 

5

http://www.nerc.com/pa/Stand/Project%20201205%20MOD%20A%20%20Available%20Transfer%20Capabilit/Consideration_of_Directiv
es_MOD_A_11122013.pdf 
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capability. Requirements R1 (part 1.2) and R2 (part 2.1) of the proposed standard require that a TOP’s and a TSP’s 
models for determining TFC, TTC, AFC or ATC, respectively, account for system topology, including additions and 
retirements as well as expected system usage, planned outages, Load forecast, and expected generation dispatch 
when  such  elements  impact  the  determination  of  TFC,  TTC,  AFC,  or  ATC.  By  describing  how  its  methodology 
accounts for these elements, adjacent systems will be able to effectively model their own transfer or Flowgate 
capabilities. The SDT concludes, however, that because each part of the country has a different sensitivity to these 
elements and the frequency with which they change, there is no additional reliability benefit in mandating the 
frequency with which a TOP or TSP must benchmark or update its models. Under Requirement R6 of the proposed 
standard, registered entities are required to share their data with others, which also increases the amount of up‐
to‐date information available for the determination of AFC or ATC values. Additionally, under Requirements R5 of 
the proposed standard, a TSP or a TOP could be asked to clarify its benchmarking or updating practices, if not 
already set forth in its  documented methodology.  As such, the  proposed reliability standard addresses  FERC’s 
directive toward increasing accuracy by improving transparency. 

GTC provided grammatical suggestions for Requirements R2, R3, and R4 as well as the appropriate requirement 
parts. The SDT considered the grammatical suggestions and made the requirements consistent in the terms used 
(see the “determine” vs. “establish” comment response). 

Portland General Electric commented that previous MODs specified the allowable TTC limits that can be applied 
for counter flow schedules and suggested that there should be more required in MOD‐001‐2 to provide some level 
of guidance for schedules in the direction counter to prevailing flows. In response, the SDT stated that by making 
MOD  A  less  prescriptive,  it  allows  individual  entities  or  individual  Regions  the  freedom  to  institute  something 
tailored to their own specific needs and concerns.  

NERC | Consideration of Comments Summary – Project 2012‐05 ATC Revisions (MOD A) | December 11, 2013 
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Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will 
be removed when the standard becomes effective.  

Development Steps Completed

1. SAR and supporting package posted for comment on (July 11, 2013 – August 27, 2013). 
2. Draft standard posted for first comment and ballot (July 11, 2013 – August 27, 2013). 
3. Draft standard posted for additional comment and ballot (November 8, 2013 ‐ 
November 20, 2013). 
4. Third posting for a 10‐day final ballot (December 2013). 
Description of Current Draft

This draft standard is being posted for a 10‐day final ballot.  

Anticipated Actions 

Anticipated Date 

Final Ballot 

December 2013 

Board of Trustees (Board) Adoption 

February 2013 

Filing to Applicable Regulatory Authorities 

February 2013 

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MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
Version History

Version 

Date 

1 

August 26, 
2008 
November 5, 
2009 

1a 
2 

TBD 

Action 

Change Tracking 

Adopted by the NERC Board  

NERC Board Adopted Interpretation of 
R2 and R8 
Consolidation of MOD‐001‐1a, MOD‐
004‐1, MOD‐008‐1, MOD‐028‐1, MOD‐
029‐1a, and MOD‐030‐2 

Interpretation 
(Project 2009‐15) 

Definitions of Terms Used in the Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms 
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or 
revised definitions listed below become approved when the proposed standard is approved. 
When the standard becomes effective, these defined terms will be removed from the individual 
standard and added to the Glossary. 
None

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When this standard receives ballot approval, the text boxes will be moved to the “Guidelines 
and Technical Basis” section of the standard. 
A. Introduction

1.

Title: 

Available Transmission System Capability 

2.

Number: 

MOD‐001‐2 

3.

Purpose: 

To ensure that determinations of available transmission system capability are 
determined in a manner that supports the reliable operation of the Bulk‐Power 
System (BPS) and that the methodology and data underlying those determinations are 
disclosed to those registered entities that need such information for reliability 
purposes.  
4.

Applicability: 
4.1. Functional Entity  
4.1.1 Transmission Operator 
4.1.2 Transmission Service Provider  
4.2. Exemptions: The following is exempt from MOD‐001‐2. 
4.2.1 Functional Entities operating within the Electric Reliability Council of 
Texas (ERCOT) 

5.

Effective Date:  
5.1. The standard shall become effective on the first day of the first calendar quarter 
that is 18 months after the date that the standard is approved by an applicable 
governmental authority or as otherwise provided for in a jurisdiction where 
approval by an applicable governmental authority is required for a standard to 
go into effect. Where approval by an applicable governmental authority is not 
required, the standard shall become effective on the first day of the first 
calendar quarter that is 18 months after the date the standard is adopted by the 
NERC Board of Trustees or as otherwise provided for in that jurisdiction. 

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B. Requirements and Measures

Rationale for R1: Total Flowgate Capability (TFC) and Total Transfer Capability (TTC) are the starting points 
for the Available Flowgate Capability (AFC) and Available Transfer Capability (ATC) values. AFC and ATC 
values influence Real‐time conditions and have the ability to impact Real‐time operations. A Transmission 
Operator (TOP) shall clearly document its methods of determining TFC and TTC so that any TOP or 
Transmission Service Provider (TSP) that uses the information can clearly understand how the values are 
determined. The TFC and TTC values shall account for any reliability‐related constraints that limit those 
values as well as system conditions forecasted for the time period for which those values are determined. 
The TFC and TTC values shall also incorporate constraints on external systems when appropriate, in 
addition to constraints on the TOP’s own system. Requirement R1 sets requirements for the determination 
of TFC or TTC, but does not establish if a TOP must determine TFC or TTC.  

R1.

Each Transmission Operator that determines Total Flowgate Capability (TFC) or Total Transfer 
Capability (TTC) shall develop a written methodology (or methodologies) for determining TFC or TTC 
values. The methodology (or methodologies) shall reflect the Transmission Operator’s current 
practices for determining TFC or TTC values. [Violation Risk Factor: Lower] [Time Horizon: Operations 
Planning] 
1.1 Each methodology shall describe the method used to account for the following limitations in 
both the pre‐ and post‐contingency state:  
1.1.1

Facility ratings; 

1.1.2

System voltage limits; 

1.1.3

Transient stability limits;  

1.1.4

Voltage stability limits; and  

1.1.5

Other System Operating Limits (SOLs).  

1.2 Each methodology shall describe the method used to account for each of the following 
elements, provided such elements impact the determination of TFC or TTC: 
1.2.1

The simulation of transfers performed through the adjustment of generation, Load, or 
both; 

1.2.2

Transmission topology, including, but not limited to, additions and retirements; 

1.2.3

Expected transmission uses; 

1.2.4

Planned outages; 

1.2.5

Parallel path (loop flow) adjustments; 

1.2.6

Load forecast; and 

1.2.7

Generator dispatch, including, but not limited to, additions and retirements. 

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1.3 Each methodology shall describe the process for including any reliability‐related constraints that 
are requested to be included by another Transmission Operator, provided that (1) the request 
references this specific requirement, and (2) the requesting Transmission Operator includes 
those constraints in its TFC or TTC determination. 
1.3.1 Each Transmission Operator that uses the Flowgate Methodology shall include in its 
methodology an impact test process for including requested constraints. If a generator to 
Load transfer in a registered entity’s area or a transfer to a neighboring registered entity 
impacts the requested constraint by five percent or greater, the requested constraint 
shall be included in the TFC determination, otherwise the requested constraint is not 
required to be included. 
1.3.2  Each Transmission Operator that uses the Area Interchange or Rated System Path 
Methodology shall describe in its methodology the process it uses to account for 
requested constraints that have a five percent or greater distribution factor for a transfer 
between areas in the TTC determination; otherwise the requested constraint is not 
required to be included. When testing transfers involving the requesting Transmission 
Operator’s area, the requested constraint may be excluded.  
1.3.3 A different method for determining whether requested constraints need to be included 
in the TFC or TTC determination may be used if agreed to by the Transmission Operators. 
M1. Each Transmission Operator that determines TFC or TTC shall provide its current written 
methodology (or methodologies) or other evidence (such as written documentation) to show that its 
methodology (or methodologies) contains the following:  


A description of the method used to account for the limits specified in part 1.1. Methods of 
accounting for these limits may include, but are not limited to, one or more of the following: 
o TFC or TTC being determined by one or more limits. 
o Simulation being used to find the maximum TFC or TTC that remains within the limit. 
o The application of a distribution factor in determining if a limit affects the TFC or TTC value. 
o Monitoring a subset of limits and a statement that those limits are expected to produce the 
most severe results. 
o A statement that the monitoring of a select limit(s) results in the TFC or TTC not exceeding 
another set of limits.   
o A statement that one or more of those limits are not applicable to the TFC or TTC 
determination. 



A description of the method used to account for the elements specified in part 1.2, provided such 
elements impact the determination of TFC or TTC. Methods of accounting for these elements 
may include, but are not limited to, one or more of the following: 
o A statement that the element is not accounted for since it does not affect the determination 
of TFC or TTC. 
o A description of how the element is used in the determination of TFC or TTC. 

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

A description of the process for including any reliability‐related constraints that are requested to 
be included by another Transmission Operator, as specified in parts 1.3, 1.3.1, 1.3.2, or 1.3.3).  



Each Transmission Operator that determines TFC or TTC shall provide evidence that currently 
active TFC or TTC values were determined based on its current written methodology, as specified 
in Requirement R1. 

Rationale for R2: A TSP must clearly document its methods of determining AFC and ATC so that TOPs or 
other entities can clearly understand how the values are determined. The AFC and ATC values shall 
account for system conditions at the time those values would be used. Each TSP that uses the Flowgate 
Methodology shall also use the AFC value determined by the TSP responsible for an external system 
constraint where appropriate. Requirement R2 sets requirements for the determination of AFC or ATC, but 
does not establish if a TSP must determine AFC or ATC.

R2.

Each Transmission Service Provider that determines Available Flowgate Capability (AFC) or Available 
Transfer Capability (ATC) shall develop an Available Transfer Capability Implementation Document 
(ATCID) that describes the methodology (or methodologies) for determining AFC or ATC values. The 
methodology (or methodologies) shall reflect the Transmission Service Provider’s current practices 
for determining AFC or ATC values. [Violation Risk Factor: Lower] [Time Horizon: Operations 
Planning] 
2.1. Each methodology shall describe the method used to account for the following elements, 
provided such elements impact the determination of AFC or ATC: 
2.1.1.

The simulation of transfers performed through the adjustment of generation, Load, or 
both; 

2.1.2.

Transmission topology, including, but not limited to, additions and retirements; 

2.1.3.

Expected transmission uses; 

2.1.4.

Planned outages;  

2.1.5.

Parallel path (loop flow) adjustments; 

2.1.6.

Load forecast; and 

2.1.7.

Generator dispatch, including, but not limited to, additions and retirements. 

2.2. Each Transmission Service Provider that uses the Flowgate Methodology shall, for reliability‐
related constraints identified in part 1.3, use the AFC determined by the Transmission Service 
Provider for that constraint. 
M2. Each Transmission Service Provider that determines AFC or ATC shall provide its current ATCID or 
other evidence (such as written documentation) to show that its ATCID contains the following: 


A description of the method used to account for the elements specified in part 2.1, provided such 
elements impact the determination of AFC or ATC. Methods of accounting for these elements 
may include, but are not limited to, one or more of the following: 

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o A description of how the element is used in the determination of AFC or ATC. 
o A statement that the element is not accounted for since it does not affect the determination 
of AFC or ATC. 
o A statement that the element is accounted for in the determination of TFC or TTC by the 
Transmission Operator, and does not otherwise affect the determination of AFC or ATC. 


For each Transmission Service Provider that uses the Flowgate Methodology, a description of the 
method in which AFC provided by another Transmission Service Provider was used for the 
reliability‐related constraints identified in part 1.3. 



Each Transmission Service Provider that determines AFC or ATC shall provide evidence that 
currently active AFC or ATC values were determined based on its current written methodology, as 
specified in Requirement R2. 

Rationale for R3: Capacity Benefit Margin (CBM) is one of the values that may be used in determining the 
AFC or ATC value. CBM is the amount of firm transmission transfer capability preserved by the transmission 
provider for Load‐Serving Entities (LSEs), whose Loads are located on that TSP’s system, to enable access by 
the LSEs to generation from interconnected systems to meet resource reliability requirements. A clear 
explanation of how the CBM value is developed is an important aspect of the TSP’s ability to communicate 
to other entities how that AFC or ATC value was determined. Therefore anytime CBM is used (non‐zero) a 
CBMID is required to communicate the method of determining CBM.

  R3.  Each Transmission Service Provider that determines Capacity Benefit Margin (CBM) values shall 
develop a Capacity Benefit Margin Implementation Document (CBMID) that describes its method for 
determining CBM values. The method described in the CBMID shall reflect the Transmission Service 
Provider’s current practices for determining CBM values. [Violation Risk Factor: Lower] [Time 
Horizon: Operations Planning] 

M3. Each Transmission Service Provider that determines CBM shall provide evidence, including, but not 
limited to, its current CBMID, current CBM values, or other evidence (such as written 
documentation, study reports, or supporting information) to demonstrate that it determined CBM 
values consistent with its methodology described in the CBMID. If a Transmission Service Provider 
does not maintain CBM, examples of evidence include, but are not limited to, an attestation, 
statement, or other documentation that states the Transmission Service Provider does not maintain 
CBM. 

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Rationale for R4: Transmission Reliability Margin (TRM) is one of the values that may be used in 
determining the AFC or ATC value. TRM accounts for the inherent uncertainty in system conditions and the 
need for operating flexibility to ensure reliable system operation as system conditions change. An 
explanation by the TOP of how the TRM value is developed for use in the TSP’s determination of AFC and 
ATC is an important aspect of the TSP’s ability to communicate to other entities how that AFC or ATC value 
was determined. Therefore, anytime a TOP provides a non‐zero TRM to a TSP, a Transmission Reliability 
Margin Implementation Document (TRMID) is required to communicate the method of determining TRM.

R4. Each Transmission Operator that determines Transmission Reliability Margin (TRM) values shall 
develop a Transmission Reliability Margin Implementation Document (TRMID) that describes its 
method for determining TRM values. The method described in the TRMID shall reflect the 
Transmission Operator’s current practices for determining TRM values. [Violation Risk Factor: 
Lower][Time Horizon: Operations Planning] 

M4. Each Transmission Operator that determines TRM shall provide evidence including, but not limited 
to, its current TRMID, current TRM values, or other evidence (such as written documentation, 
study reports, or supporting information) to demonstrate that it determined TRM values 
consistent with its methodology described in the TRMID. If a Transmission Operator does not 
maintain TRM, examples of evidence include, but are not limited to, an attestation, statement, or 
other documentation that states the Transmission Operator does not maintain TRM. 
Rationale for R5: Clear communication of the methods of determining AFC, ATC, CBM, TFC, TRM, and TTC 
are necessary to the reliable operation of the Bulk‐Power System (BPS). A TOP and TSP are obligated to 
make available their methodologies for determining AFC, ATC, CBM, TFC, TRM, and TTC to those with a 
reliability need. The TOP and TSP are further obligated to respond to any requests for clarification on those 
methodologies, provided that responding to such requests would not be contrary to the registered entities 
confidentiality, regulatory, or security concerns. The purpose of this requirement is not to monitor every 
communication that occurs regarding these values, but to ensure that those with reliability need have 
access to the information. Therefore, the requirement is very specific on when it is invoked so that it does 
not create an administrative burden on regular communications between registered entities. 

R5. Within 45 calendar days of receiving a written request that references this specific requirement 
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission 
Planner, Transmission Service Provider, or any other registered entity that demonstrates a 
reliability need, each Transmission Operator or Transmission Service Provider shall provide: 
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning] 
5.1.

A written response to any request for clarification of its TFC or TTC methodology, ATCID, 
CBMID, or TRMID. If the request for clarification is contrary to the Transmission Operator’s 
or Transmission Service Provider’s confidentiality, regulatory, or security requirements 
then a written response shall be provided explaining the clarifications not provided, on 

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what basis and whether there are any options for resolving any of the confidentiality, 
regulatory, or security concerns. 
5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s 
effective: 
5.2.1 TRMID; and 
5.2.2 TFC or TTC methodology. 

5.3.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s 
effective: 
5.3.1 ATCID; and 
5.3.2 CBMID. 

M5. Examples of evidence include, but are not limited to:  
 Dated records of the request and the Transmission Operator’s or Transmission Service 
Provider’s response to the request; 
 A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests; or 
 A statement by the Transmission Operator or Transmission Service Provider that they do not 
determine one or more of these values: AFC, ATC, CBM, TFC, TTC or TRM.   
Rationale for R6: This requirement provides a mechanism for each TOP or TSP to access the best available 
data for use in its calculation of AFC, ATC, CBM, TFC, TRM, and TTC values. Requirement R6 requires that a 
TOP or TSP share their data, with the caveat that the TOP or TSP is not required to modify that data from 
the form that they use or maintain it in. For data requests that involve providing data on a regular interval, 
the TOP or TSP is not obligated to provide the data more frequently than either (1) once an hour, or (2) as 
often as they update the data. The data provider is also not obligated to provide data that would violate 
any of its confidentiality, regulatory, or security obligations. The purpose of this requirement is not to 
monitor every data exchange that occurs regarding these values, but to ensure that those with reliability 
need have access to the information. Therefore, the requirement is very specific on when it is invoked so 
that it does not create an administrative burden on regular communications between registered entities.  

R6. Each Transmission Operator or Transmission Service Provider that receives a written request from 
another Transmission Operator or Transmission Service Provider for data related to AFC, ATC, TFC, 
or TTC determinations that (1) references this specific requirement, and (2) specifies that the 
requested data is for use in the requesting party’s AFC, ATC, TFC, or TTC determination shall take 
one of the actions below. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning] 
6.1. In responding to a written request for data on an ongoing basis, the Transmission Service 
Provider or Transmission Operator shall make available its data on an ongoing basis no later 

Draft 3: December 11, 2013  

Page 9 of 19 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
than 45 calendar days from receipt of the written request. Unless otherwise agreed upon, 
the Transmission Operator or Transmission Service Provider is not required to:   
6.1.1 Alter the format in which it maintains or uses the data; or 
6.1.2 Make available the requested data on a more frequent basis than it produces the 
data and in no event shall it be required to provide the data more frequently than 
once an hour. 
6.2 In responding to all other data requests, each Transmission Operator or Transmission Service 
Provider shall make available the requested data within 45 calendar days of receipt of the 
written request. Unless otherwise agreed upon, the Transmission Operator or Transmission 
Service Provider is not required to alter the format in which it maintains or uses the data.
6.3 If making available any requested data under parts 6.1 or 6.2 of this requirement is contrary 
to the Transmission Operator’s or Transmission Service Provider’s confidentiality, regulatory, 
or security requirements, the Transmission Operator or Transmission Service Provider shall 
not be required to make available that data; provided that, within 45 calendar days of the 
written request, it responds to the requesting registered entity specifying the data that is not 
being provided, on what basis and whether there are any options for resolving any of the 
confidentiality, regulatory or security concerns.   
M6. Examples of evidence for a data request that involves providing data on an ongoing basis (6.1), 
include, but are not limited to: 


Dated records of a registered entity’s request, and examples of the response being met;  



Dated records of a registered entity’s request, and a statement from the requestor that the 
request was met (demonstration that the response was met is not required if the requestor 
confirms it is being provided); or 



A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests under this requirement.  

Examples of evidence for all other data requests (6.2) include, but are not limited to:  


Dated records of a registered entity’s request, and the response to the request;  



Dated records of a registered entity’s request, and a statement from the requestor that the 
request was met; or 



A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests under this requirement.  

An example of evidence of a response by the Transmission Operator or Transmission Service 
Provider that providing the data would be contrary to the registered entity’s confidentiality, 
regulatory, or security requirements (6.3) is a response to the requestor specifying the data that is 
not being provided, on what basis and whether there are any options for resolving any of the 
confidentiality, regulatory, or security concerns.  

Draft 3: December 11, 2013  

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MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
C. Compliance

1.

Compliance Monitoring Process: 
1.1. Compliance Enforcement Authority: 
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” refers 
to NERC or the Regional Entity in their respective roles of monitoring and enforcing 
compliance with the NERC Reliability Standards. 
1.2. Evidence Retention:  
The following evidence retention periods identify the period of time a registered entity 
is required to retain specific evidence to demonstrate compliance. For instances in 
which the evidence retention period specified below is shorter than the time since the 
last audit, the Compliance Enforcement Authority may ask the registered entity to 
provide other evidence to show that it was compliant for the full time period since the 
last audit.  


Implementation and methodology documents shall be retained for five years. 



Components of the calculations and the results of such calculations for all values 
contained in the implementation and methodology documents. 
o Hourly values for the most recent 14 days;  
o Daily values for the most recent 30 days; and  
o Monthly values for the most recent 60 days. 



If a Transmission Operator or Transmission Service Provider is found non‐compliant, 
it shall keep information related to the non‐compliance until mitigation is complete 
and approved. 



The Compliance Enforcement Authority shall keep the last audit records and all 
requested and submitted subsequent audit records.  

1.3. Compliance Monitoring and Assessment Processes: 


 “Compliance Monitoring and Assessment Processes” refers to the identification of 
the processes that will be used to evaluate data or information for the purpose of 
assessing performance or outcomes with the associated reliability standard. 

1.4. Additional Compliance Information: 


None 

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MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
Table of Compliance Elements
R # 

R1 

Time 
Horizon 
Operations 
Planning 

Draft 3: December 11, 2013 

VRF 

Lower 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for one of the 
limitations listed in 
part 1.1 in its written 
methodology. (1.1) 

OR 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for one of the element 
listed in part 1.2 in its 
written methodology, 
provided that element 
impacts its TFC or TTC 
determination. (1.2) 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for two of the 
limitations listed in 
part 1.1 in its written 
methodology. (1.1) 

OR  

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for two, three, or four 
elements listed in part 
1.2 in its written 
methodology, 
provided those 
elements impacts its 
TFC or TTC 
determination. (1.2) 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for any of the 
limitations listed in 
part 1.1 in its written 
methodology. (1.1) 

OR 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for five, six, or seven 
elements of listed in 
part 1.2 in its written 
methodology, 
provided those 
elements impacts its 
TFC or TTC 
determination. (1.2) 

OR 

Each Transmission 
Operator that 
determines TFC or TTC 
did not develop a 
written methodology 
for describing its 
current practices for 
determining TFC or 
TTC values. 

OR 

Each Transmission 
Operator that 
determines TFC or TTC 
developed a written 
methodology for 
determining TFC or 
TTC but the 
methodology did not 
reflect its current 
practices for 
determining TFC or 
TTC values. 

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MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described the 
process for including 
any reliability‐related 
constraints that have 
been requested by 
another Transmission 
Operator, provided the 
constraints are also 
used in the requesting 
Transmission 
Operator’s TFC or TTC 
calculation and the 
request referenced 
part 1.3. (1.3) 

OR  

Each Transmission 
Operator that 
determines TFC or TTC 
has not used (i) an 
impact test process for 
including requested 
constraints, (ii) a 
process to account for 
requested constraints 
Draft 3: December 11, 2013 

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MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R2 

Operations 
Planning 

Draft 3: December 11, 2013 

Lower 

Moderate VSL 

High VSL 

that have a five 
percent or greater 
distribution factor for 
a transfer between 
areas in the TTC 
determination, or (iii) a 
mutually agreed upon 
method for 
determining whether 
requested constraints 
need to be included in 
the TFC or TTC 
determination. (1.3.1, 
1.3.2, 1.3.3) 
Each Transmission 
Each Transmission 
Each Transmission 
Service Provider that 
Service Provider that 
Service Provider that 
determines AFC or ATC  determines AFC or ATC  determines AFC or ATC 
has not described its 
has not described its 
has not described its 
method for accounting  method for accounting  method for accounting 
for one of the 
for two, three, or four  for five, six, or seven 
elements listed in part  elements listed in part  elements listed in part 
2.1 in its written 
2.1 in its written 
2.1 in its written 
methodology, 
methodology, 
methodology, 
provided that element  provided the elements  provided the elements 
impacts its AFC or ATC  impact its AFC or ATC  impact its AFC or ATC 
determination. (2.1) 
determination. (2.1) 
determination. (2.1) 

OR 

Severe VSL 

Each Transmission 
Service Provider that 
determines AFC or ATC 
did not develop an 
ATCID describing its 
AFC or ATC 
methodology. 

OR 

Each Transmission 
Service Provider that 
determines AFC or ATC 
did not reflect its 
current practices for 
Page 14 of 19 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R3 

Operations 
Planning  

Draft 3: December 11, 2013 

Lower 

None. 

Moderate VSL 

None. 

High VSL 
Each Transmission 
Service Provider that 
uses the Flowgate 
Methodology did not 
use the AFC 
determined by the 
Transmission Service 
Provider for reliability‐
related constraints 
identified in part 1.3. 
(2.2) 
None. 

Severe VSL 
determining AFC or 
ATC values in its 
ATCID. 

Each Transmission 
Service Provider that 
determines CBM 
values did not develop 
a CBMID describing its 
method for 
determining CBM 
values. 

OR 

Each Transmission 
Service Provider that 
determines CBM 
values did not reflect 
its current practices 
for determining CBM 
values in its CBMID. 
Page 15 of 19 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R4 

Operations 
Planning 

Lower 

R5 

Operations 
Planning 

Lower 

Draft 3: December 11, 2013 

None. 

Moderate VSL 
None. 

High VSL 

Severe VSL 

None. 

Each Transmission 
Operator that 
determines TRM 
values did not develop 
a TRMID describing its 
method for 
determining TRM 
values. 

OR 

Each Transmission 
Operator that 
determines TRM 
values did not reflect 
its current practices 
for determining TRM 
values in its TRMID. 
Each Transmission 
Each Transmission 
Each Transmission 
Each Transmission 
Operator or 
Operator or 
Operator or 
Operator or 
Transmission Service 
Transmission Service 
Transmission Service 
Transmission Service 
Provider failed to 
Provider did not 
Provider did not 
Provider did not 
respond in writing to a  respond in writing to a  respond in writing to a  respond in writing to a 
written request by one  written request by one  written request by one  written request by one 
or more of the 
or more of the 
or more of the 
or more of the 
registered entities 
registered entities 
registered entities 
registered entities 
specified in 
specified in 
specified in 
specified in 
Requirement R5 within  Requirement R5 within  Requirement R5 within  Requirement R5. 

45 calendar days from  76 calendar days from  106 calendar days 
Page 16 of 19 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R6 

Operations 
Planning 

Draft 3: December 11, 2013 

Lower 

the date of the 
request, but did 
respond in writing 
within 75 calendar 
days. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respond to a written 
request for data by 
one or more of the 
registered entities 
specified in 
Requirement R6 by 
making the requested 
data available within 
45 calendar days from 
the date of the 
request, but did 
respond within 75 
calendar days. 

Moderate VSL 
the date of the 
request, but did 
respond in writing 
within 105 calendar 
days. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respond to a written 
request for data by 
one or more of the 
registered entities 
specified in 
Requirement R6 by 
making data available 
within 76 calendar 
days from the date of 
the request, but did 
respond within 105 
calendar days. 

High VSL 
from the date of the 
request, but did 
respond in writing 
within 135 calendar 
days. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respond to a written 
request by one or 
more of the registered 
entities specified in 
Requirement R6 by 
making data available 
within 106 calendar 
days from the date of 
the request, but did 
respond within 135 
calendar days. 

Severe VSL 

Each Transmission 
Operator or 
Transmission Service 
Provider failed to 
respond to a written 
request for data by 
making data available 
to one or more of the 
entities specified in 
Requirement R6. 

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MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

D. Regional Variances

None. 
E. Interpretations

None. 
F. Associated Documents

None. 

Draft 3: December 11, 2013 

Page 18 of 19 

Application Guidelines 
Guidelines and Technical Basis
Please see the MOD A White Paper for further information regarding the technical basis for 
each requirement.

Draft 3: December 11, 2013 

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MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

Standard Development Timeline

This section is maintained by the drafting team during the development of the standard and will 
be removed when the standard becomes effective.  

Development Steps Completed

1. SAR and supporting package posted for comment on (July 11, 2013 – August 27, 2013). 
2. Draft standard posted for first comment and ballot (July 11, 2013 – August 27, 2013). 
3. Draft standard posted for additional comment and ballot (November 8, 2013 ‐ 
November 2018, 2013). 
3.4.

Third posting for a 10‐day final ballot (December 2013). 

Description of Current Draft

This draft standard is concluding informal development and will move to formal development 
when authorized by the Standards Committee.being posted for a 10‐day final ballot.  

Anticipated Actions 

Anticipated Date 

Additional 45‐day Formal Comment Period with Ballot 

November 2013 

Final Ballot 

December 2013 

Board of Trustees (Board) Adoption 

FebruaryDecember 
2013 

Filing to Applicable Regulatory Authorities 

December February 
2013 

Draft 32: December 11October 4, 2013   

Page 1 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
Version History

Version 

Date 

1 

August 26, 
2008 
November 5, 
2009 

1a 
2 

TBD 

Action 

Change Tracking 

Adopted by the NERC Board  

NERC Board Adopted Interpretation of 
R2 and R8 
Consolidation of MOD‐001‐1a, MOD‐
004‐1, MOD‐008‐1, MOD‐028‐1, MOD‐
029‐1a, and MOD‐030‐2 

Interpretation 
(Project 2009‐15) 

Definitions of Terms Used in the Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms 
already defined in the Reliability Standards Glossary of Terms are not repeated here. New or 
revised definitions listed below become approved when the proposed standard is approved. 
When the standard becomes effective, these defined terms will be removed from the individual 
standard and added to the Glossary. 
None

Draft 32: December 11October 4, 2013   

Page 2 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
When this standard receives ballot approval, the text boxes will be moved to the “Guidelines 
and Technical Basis” section of the standard. 
A. Introduction

1.

Title: 

Available Transmission System Capability 

2.

Number: 

MOD‐001‐2 

3.

Purpose: 

To ensure that determinations of available transmission system transfer capability are 
determined in a manner that supports the reliable operation of the Bulk‐Power 
System (BPS) and that the methodology and data underlying those determinations are 
disclosed to those registered entities that need such information for reliability 
purposes. This Reliability Standard ensures (1) that available transmission system 
capability determinations account for system reliability limits, and (2) that planners 
and operators of the BPS can request available transmission system capability 
information from other Transmission Operators or Transmission Services Providers.  
4.

Applicability: 
4.1. Functional Entity  
4.1.1 Transmission Operator 
4.1.2 Transmission Service Provider  
4.2. Exemptions: The following is exempt from MOD‐001‐2. 
4.2.1 Functional Entities operating within the Electric Reliability Council of 
Texas (ERCOT) 

5.

Effective Date:  
5.1. The standard shall become effective on the first day of the first calendar quarter 
that is 18 months after the date that the standard is approved by an applicable 
governmental authority or as otherwise provided for in a jurisdiction where 
approval by an applicable governmental authority is required for a standard to 
go into effect. Where approval by an applicable governmental authority is not 
required, the standard shall become effective on the first day of the first 
calendar quarter that is 18 months after the date the standard is adopted by the 
NERC Board of Trustees or as otherwise provided for in that jurisdiction. 

Draft 32: December 11October 4, 2013   

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B. Requirements and Measures

Rationale for R1: Total Flowgate Capability (TFC) and Total Transfer Capability (TTC) are the starting points 
for the Available Flowgate Capability (AFC) and Available Transfer Capability (ATC) values. AFC and ATC 
values influence Realreal‐time conditions and have the ability to impact Realreal‐time operations. A 
Transmission Operator (TOP) shall clearly document its methods of determining TFC and TTC so that any 
TOP or Transmission Service Provider (TSP) that uses the information can clearly understand how the 
values are determined. The TFC and TTC values shall account for any reliability‐related constraints that limit 
those values as well as system conditions forecasted for the time period for which those values are 
determined. The TFC and TTC values shall also incorporate constraints on external systems when 
appropriate, in addition to constraints on the TOP’s own system. Requirement R1 sets requirements for the 
determination of TFC or TTC, but does not establish if a TOP must determine TFC or TTC.  

R1.

Each Transmission Operator that determines Total Flowgate Capability (TFC) or Total Transfer 
Capability (TTC) shall develop a written methodology (or methodologies) for determining TFC or TTC 
values. The methodology (or methodologies) shall reflect the Transmission Operator’s current 
practices for determining TFC or TTC values. [Violation Risk Factor: Lower] [Time Horizon: Operations 
Planning] 
1.1 Each methodology shall describe the method used to account for the following limitations in 
both the pre‐ and post‐contingency state:  
1.1.1

Facility ratings; 

1.1.2

System voltage limits; 

1.1.3

Transient stability limits;  

1.1.4

Voltage stability limits; and  

1.1.5

Other System Operating Limits (SOLs).  

1.2 Each methodology shall describe the method used to account for each of the following 
elements, provided such elements impact the determination of TFC or TTC: 
1.2.1

The simulation of transfers performed through the adjustment of generation, Load, or 
both; 

1.2.2

Transmission topology, including, but not limited to, additions and retirements; 

1.2.3

Expected transmission uses; 

1.2.4

Planned outages; 

1.2.5

Parallel path (loop flow) adjustments; 

1.2.6

Load forecast; and 

1.2.7

Generator dispatch, including, but not limited to, additions and retirements. 

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1.3 Each methodology shall describe the process for including any reliability‐related constraints that 
are requested to be included by another Transmission Operator, provided that (1) the request 
references this specific requirement, and (2) the requesting Transmission Operator includes 
those constraints in its TFC or TTC determination. 
1.3.1 Each Transmission Operator that uses the Flowgate Methodology shall include in its 
methodology an impact test process for including requested constraints. If a generator to 
Load transfer in a registered entity’s area or a transfer to a neighboring registered entity 
impacts the requested constraint by five percent or greater, the requested constraint 
shall be included in the TFC determination, otherwise the requested constraint is not 
required to be included. 
1.3.2  Each Transmission Operator that uses the Area Interchange or Rated System Path 
Methodology shall describe in its methodology the process it uses to account for 
requested constraints that have a five percent or greater distribution factor for a transfer 
between areas in the TTC determination; otherwise the requested constraint is not 
required to be included. When testing transfers involving the requesting Transmission 
Operator’s area, the requested constraint may be excluded.  
1.3.3 A different method for determining whether requested constraints need to be included 
in the TFC or TTC determination may be used if agreed to by the Transmission Operators. 
M1. Each Transmission Operator that determines TFC or TTC shall provide its current written 
methodology (or methodologies) or other evidence (such as written documentation) to show that its 
methodology (or methodologies) contains the following:  


A description of the method used to account for the limits specified in part 1.1. Methods of 
accounting for these limits may include, but are not limited to, one or more of the following: 
o TFC or TTC being determined by one or more limits. 
o Simulation being used to find the maximum TFC or TTC that remains within the limit. 
o The application of a distribution factor in determining if a limit affects the TFC or TTC value. 
o Monitoring a subset of limits and a statement that those limits are expected to produce the 
most severe results. 
o A statement that the monitoring of a select limit(s) results in the TFC or TTC not exceeding 
another set of limits.   
o A statement that one or more of those limits are not applicable to the TFC or TTC 
determination. 



A description of the method used to account for the elements specified in part 1.2, provided such 
elements impact the determination of TFC or TTC. Methods of accounting for these elements 
may include, but are not limited to, one or more of the following: 
o A statement that the element is not accounted for since it does not affect the determination 
of TFC or TTC. 
o A description of how the element is used in the determination of TFC or TTC. 

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

A description of the process for including any reliability‐related constraints that are requested to 
be included by another Transmission Operator, as specified in parts 1.3, 1.3.1, 1.3.2, or 1.3.3). 
(1.3) A copy of the request and a description of the method used to perform the impact test 
(1.3.1) or account for the requested constraints (1.3.2).  
The Transmission Operator shall also be using their current method to determine TFC or TTC.  
Evidence of this could be, but is not limited to, a demonstration that a selection of currently 
active TFC or TTC values were calculated based on current the methodology.   



Each Transmission Operator that determines TFC or TTC shall provide evidence that currently 
active TFC or TTC values were determined based on its current written methodology, as specified 
in Requirement R1. 

Rationale for R2: A TSP must clearly document its methods of determining AFC and ATC so that TOPs or 
other entities can clearly understand how the values are determined. The AFC and ATC values shall 
account for system conditions at the time those values would be used. Each TSP that uses the Flowgate 
Methodology shall also use the AFC value determined by the TSP responsible for an external system 
constraint where appropriate. Requirement R2 sets requirements for the determination of AFC or ATC, but 
does not establish if a TSP must determine AFC or ATC.

R2.

Each Transmission Service Provider that determines Available Flowgate Capability (AFC) or Available 
Transfer Capability (ATC) shall develop an Available Transfer Capability Implementation Document 
(ATCID) that describes the methodology (or methodologies) it uses tofor determine determining AFC 
or ATC values. The methodology (or methodologies) shall reflect the Transmission Service Provider’s 
current practices for determining AFC or ATC values. [Violation Risk Factor: Lower] [Time Horizon: 
Operations Planning] 
2.1. Each methodology shall describe the method used to account for the following elements that, 
provided such elements impact the determination of AFC or ATC: 
2.1.1.

The simulation of transfers performed through the adjustment of generation, Load, or 
both; 

2.1.2.

Transmission topology, including, but not limited to, additions and retirements; 

2.1.3.

Expected transmission uses; 

2.1.4.

Planned outages;  

2.1.5.

Parallel path (loop flow) adjustments; 

2.1.6.

Load forecast; and 

2.1.7.

Generator dispatch, including, but not limited to, additions and retirements. 

2.2. Each Transmission Service Provider that uses the Flowgate Methodology shall, for reliability‐
related constraints identified in part 1.3, use the AFC determined by the Transmission Service 
Provider for that constraint. 

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M2. Each Transmission Service Provider that determines AFC or ATC shall provide its current ATCID or 
other evidence (such as written documentation) to show that its ATCID contains the following: 


A description of the method used to account for the elements specified in part 2.1, provided such 
elements impact the determination of AFC or ATC. Methods of accounting for these elements 
may include, but are not limited to, one or more of the following: 
o A description of how the element is used in the determination of AFC or ATC. 
o A statement that the element is not accounted for since it does not affect the determination 
of AFC or ATC. 
o A statement that the element is accounted for in the determination of TFC or TTC by the 
Transmission Operator, and does not otherwise affect the determination of AFC or ATC. 



For eEach Transmission Service Provider that uses the Flowgate Methodology, shall provide a  
description of the method in which AFC provided by another Transmission Service Provider was 
used for the reliability‐related constraints identified in part 1.3. 



The Transmission Service Provider shall also be using their current method to determine AFC or 
ATC. Evidence of this could be, but is not limited to, a demonstration that a selection of currently 
active AFC or ATC values were calculated based on the current methodology. 



Each Transmission Service Provider that determines AFC or ATC shall provide evidence that 
currently active AFC or ATC values were determined based on its current written methodology, as 
specified in Requirement R2. 

Rationale for R3: Capacity Benefit Margin (CBM) is one of the values that may be used in determining the 
AFC or ATC value. CBM is the amount of firm transmission transfer capability preserved by the transmission 
provider for Load‐Serving Entities (LSEs), who’se Loads are located on that TSP’s system, to enable access 
by the LSEs to generation from interconnected systems to meet resource reliability requirements. A clear 
explanation of how the CBM value is developed is an important aspect of the TSP’s ability to communicate 
to TOPs other entities how that AFC or ATC value was determined. Therefore anytime CBM is used (non‐
zero) a CBMID is required to communicate the method of determining CBM.

  R3.  Each Transmission Service Provider that determines Capacity Benefit Margin (CBM) values shall 
develop a Capacity Benefit Margin Implementation Document (CBMID) that describes its method for 
establishing determining CBM values. The method described in the CBMID shall reflect the 
Transmission Service Provider’s current practices for determining CBM values. [Violation Risk Factor: 
Lower] [Time Horizon: Operations Planning] 

M3. Each Transmission Service Provider that determines CBM shall provide evidence, including, but not 
limited to, its current CBMID, current CBM values, or other evidence (such as written 
documentation, study reports, or supporting information) to demonstrate that it established 
determined CBM values consistent with its methodology described in the CBMID. If a Transmission 
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Service Provider does not maintain CBM, examples of evidence include, but are not limited to, an 
affidavitattestation, statement, or other documentation that states the Transmission Service 
Provider does not maintain CBM. 

Rationale for R4: Transmission Reliability Margin (TRM) is one of the values that may be used in 
determining the AFC or ATC value. TRM accounts for the inherent uncertainty in system conditions and the 
need for operating flexibility to ensure reliable system operation as system conditions change. An 
explanation by the TOP of how the TRM value is developed for use in the TSP’s determination of AFC and 
ATC is an important aspect of the TSP’s ability to communicate to other entities TOPs how that AFC or ATC 
value was determined. Therefore, anytime a TOP provides a non‐zero TRM to a TSP, a Transmission 
Reliability Margin Implementation Document (TRMID) is required to communicate the method of 

R4. Each Transmission Operator that determines Transmission Reliability Margin (TRM) values shall 
develop a Transmission Reliability Margin Implementation Document (TRMID) that describes its 
method for establishing determining TRM values. The method described in the TRMID shall reflect 
the Transmission Operator’s current practices for determining TRM values. [Violation Risk Factor: 
Lower][Time Horizon: Operations Planning] 

M4. Each Transmission Operator that determines TRM shall provide evidence including, but not limited 
to, its current TRMID, current TRM values, or other evidence (such as written documentation, 
study reports, or supporting information) to demonstrate that it established determined TRM 
values consistent with its methodology described in the TRMID. If a Transmission Operator does 
not maintain TRM, examples of evidence include, but are not limited to, an affidavitattestation, 
statement, or other documentation that states the Transmission Operator does not maintain TRM. 
Rationale for R5: Clear communication of the methods of determining AFC, ATC, CBM, TFC, TRM, and TTC 
are necessary to the reliable operation of the Bulk‐Power System (BPS). A TOP and TSP are obligated to 
make available their methodologies for determining AFC, ATC, CBM, TFC, TRM, and TTC to those with a 
reliability need. The TOP and TSP are further obligated to respond to any requests for clarification on those 
methodologies, provided that responding to such requests would not be contrary to the registered entities 
confidentiality, regulatory, or security concerns. The purpose of this requirement is not to monitor every 
communication that occurs regarding these values, but to ensure that those with reliability need have 
access to the information. Therefore, the requirement is very specific on when it is invoked so that it does 
not create an administrative burden on regular communications between registered entities. 

R5. Within 45 calendar days of receiving a written request that references this specific requirement 
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission 
Planner, Transmission Service Provider, or any other registered entity that demonstrates a 

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reliability need, each Transmission Operator or Transmission Service Provider shall provide: 
[Violation Risk Factor: Lower] [Time Horizon: Operations Planning] 
5.1.

A written response to any request for clarification of its TFC or TTC methodology, ATCID, 
CBMID, or TRMID. If the request for clarification is contrary to the Transmission Operator’s 
or Transmission Service Provider’s confidentiality, regulatory, or security requirements 
then a written response shall be provided explaining the clarifications not provided, on 
what basis and whether there are any options for resolving any of the confidentiality, 
regulatory, or security concerns. 

5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s 
effective: 
5.2.1 TRMID; and 
5.2.2 TFC or TTC methodology. 

5.3.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s 
effective: 
5.3.1 ATCID; and 
5.3.2 CBMID. 

M5. Examples of evidence include, but are not limited to:  
 Dated records of the request and the Transmission Operator’s or Transmission Service 
Provider’s response to the request; 
 A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests; or 
 A statement by the Transmission Operator or Transmission Service Provider that they do not 
determine one or more of these values: AFC, ATC, CBM, TFC, TTC or TRM.   
Rationale for R6: This requirement provides a mechanism for each TOP or TSP to access the best available 
data for use in its calculation of AFC, ATC, CBM, TFC, TRM, and TTC values. Requirement R6 requires that a 
TOP orand TSP share their data, with the caveat that the TOP orand TSP is not required to modify that data 
from the form that they use or maintain it in. For data requests that involve providing data on a regular 
interval, the TOP orand TSP is not obligated to provide the data more frequently than either (1) once an 
hour, or (2) as often as they update the data. The data provider is also not obligated to provide data that 
would violate any of its confidentiality, regulatory, or security obligations. The purpose of this requirement 
is not to monitor every data exchange that occurs regarding these values, but to ensure that those with 
reliability need have access to the information. Therefore, the requirement is very specific on when it is 
invoked so that it does not create an administrative burden on regular communications between registered 
entities.  

R6. Each Transmission Operator or Transmission Service Provider that receives a written request from 
another Transmission Operator or Transmission Service Provider for data related to AFC, ATC, TFC, 
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or TTC determinations that (1) references this specific requirement, and (2) specifies that the 
requested data is for use in the requesting party’s AFC, ATC, TFC, or TTC determination shall take 
one of the actions below. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning] 
6.1. In responding to a written request for data on an ongoing basis, the Transmission Service 
Provider or Transmission Operator shall make available its data on an ongoing basis no later 
than 45 calendar days from receipt of the written request. Unless otherwise agreed upon, 
the Transmission Operator or Transmission Service Provider is not required to:   
6.1.1 Alter the format in which it maintains or uses the data; or 
6.1.2 Make available the requested data on a more frequent basis than it produces the 
data and in no event shall it be required to provide the data more frequently than 
once an hour. 
6.2 In responding to all other data requests, each Transmission Operator or Transmission Service 
Provider shall make available the requested data within 45 calendar days of receipt of the 
written request. Unless otherwise agreed upon, the Transmission Operator or Transmission 
Service Provider is not required to alter the format in which it maintains or uses the data.
6.3 If making available any requested data under parts 6.1 or 6.2 of this requirement is contrary 
to the Transmission Operator’s or Transmission Service Provider’s confidentiality, regulatory, 
or security requirements, the Transmission Operator or Transmission Service Provider shall 
not be required to make available that data; provided that, within 45 calendar days of the 
written request, it responds to the requesting registered entity specifying the data that is not 
being provided, on what basis and whether there are any options for resolving any of the 
confidentiality, regulatory or security concerns.   
M6. Examples of evidence for a data request that involves providing data at regular intervals on an 
ongoing basis (6.1), include, but are not limited to: 


Dated records of a registered entity’s request, and examples of the response being met;  



Dated records of a registered entity’s request, and a statement from the requestor that the 
request was met (demonstration that the response was met is not required if the requestor 
confirms it is being provided); or 



A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests under this requirement.  

Examples of evidence for all other data requests (6.2) include, but are not limited to:  


Dated records of a registered entity’s request, and the response to the request;  



Dated records of a registered entity’s request, and a statement from the requestor that the 
request was met; or 



A statement by the Transmission Operator or Transmission Service Provider that they have 
received no requests under this requirement.  

An example of evidence of a response by the Transmission Operator or Transmission Service 
Provider that providing the data would be contrary to the registered entity’s confidentiality, 
Draft 32: October 4December 11, 2013  

Page 10 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
regulatory, or security requirements (6.3) isincludes a response to the requestor specifying the 
data that is not being provided, on what basis and whether there are any options for resolving any 
of the confidentiality, regulatory, or security concerns.  

Draft 32: October 4December 11, 2013  

Page 11 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
C. Compliance

1.

Compliance Monitoring Process: 
1.1. Compliance Enforcement Authority: 
As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” refers 
to NERC or the Regional Entity in their respective roles of monitoring and enforcing 
compliance with the NERC Reliability Standards. 
1.2. Evidence Retention:  
The following evidence retention periods identify the period of time a registered entity 
is required to retain specific evidence to demonstrate compliance. For instances in 
which the evidence retention period specified below is shorter than the time since the 
last audit, the Compliance Enforcement Authority may ask the registered entity to 
provide other evidence to show that it was compliant for the full time period since the 
last audit.  


Implementation and methodology documents shall be retained for five years. 



Components of the calculations and the results of such calculations for all values 
contained in the implementation and methodology documents. 
o Hourly values for the most recent 14 days;  
o Daily values for the most recent 30 days; and  
o Monthly values for the most recent 60 days. 



If a Transmission Operator or Transmission Service Provider is found non‐compliant, 
it shall keep information related to the non‐compliance until mitigation is complete 
and approved. 



The Compliance Enforcement Authority shall keep the last audit records and all 
requested and submitted subsequent audit records.  

1.3. Compliance Monitoring and Assessment Processes: 


As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment 
Processes” refers to the identification of the processes that will be used to evaluate 
data or information for the purpose of assessing performance or outcomes with the 
associated reliability standard. 

1.4. Additional Compliance Information: 


None 

Draft 32: October 4December 11, 2013 

Page 12 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 
Table of Compliance Elements
R # 

R1 

Time 
Horizon 
Operations 
Planning 

VRF 

Lower 

Draft 23: October 4December 11, 2013 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for one of the 
limitations listed in 
part 1.1 in its written 
methodology. (1.1) 

OR 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for one of the element 
listed in part 1.2 in its 
written methodology, 
provided that element 
impacts its TFC or TTC 
determination. (1.2) 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for two of the 
limitations listed in 
part 1.1 in its written 
methodology. (1.1) 

OR  

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for two, three, or four 
elements listed in part 
1.2 in its written 
methodology, 
provided those 
elements impacts its 
TFC or TTC 
determination. (1.2) 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for any of the 
limitations listed in 
part 1.1 in its written 
methodology. (1.1) 

OR 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described its 
method for accounting 
for five, six, or seven 
elements of listed in 
part 1.2 in its written 
methodology, 
provided those 
elements impacts its 
TFC or TTC 
determination. (1.2) 

OR 

Each Transmission 
Operator that 
determines TFC or TTC 
did not develop a 
written methodology 
for describing its 
current practices for 
determining TFC or 
TTC values. 

OR 

Each Transmission 
Operator that 
determinesuses TFC or 
TTC developed a 
written methodology 
for determining TFC or 
TTC but the 
methodology did not 
reflect its current 
practices for 
determining TFC or 
TTC values. 

Page 13 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

Moderate VSL 

High VSL 

Severe VSL 

Each Transmission 
Operator that 
determines TFC or TTC 
has not described the 
process for including 
any reliability‐related 
constraints that have 
been requested by 
another Transmission 
Operator, provided the 
constraints are also 
used in the requesting 
Transmission 
Operator’s TFC or TTC 
calculation and the 
request referenced 
part 1.3. (1.3) 

OR  

Each Transmission 
Operator that 
determines TFC or TTC 
has not used (i) an 
impact test process for 
including requested 
constraints, (ii) a 
process to account for 
requested constraints 
Draft 23: October 4December 11, 2013 

Page 14 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R2 

Operations 
Planning 

Lower 

Draft 23: October 4December 11, 2013 

Moderate VSL 

High VSL 

that have a five 
percent or greater 
distribution factor for 
a transfer between 
areas in the TTC 
determination, or (iii) a 
mutually agreed upon 
method for 
determining whether 
requested constraints 
need to be included in 
the TFC or TTC 
determination. (1.3.1, 
1.3.2, 1.3.3) 
Each Transmission 
Each Transmission 
Each Transmission 
Service Provider that 
Service Provider that 
Service Provider that 
determines AFC or ATC  determines AFC or ATC  determines AFC or ATC 
has not described its 
has not described its 
has not described its 
method for accounting  method for accounting  method for accounting 
for one of the 
for two, three, or four  for five, six, or seven 
elements listed in part  elements listed in part  elements listed in part 
2.1 in its written 
2.1 in its written 
2.1 in its written 
methodology, 
methodology, 
methodology, 
provided that element  provided the elements  provided the elements 
impacts its AFC or ATC  impact its AFC or ATC  impact its AFC or ATC 
determination. (2.1) 
determination. (2.1) 
determination. (2.1) 

OR 

Severe VSL 

Each Transmission 
Service Provider that 
determines AFC or ATC 
did not develop an 
ATCID describing its 
AFC or ATC 
methodology. 

OR 

Each Transmission 
Service Provider that 
determines AFC or ATC 
did not reflect its 
current practices for 
Page 15 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R3 

Operations 
Planning  

Lower 

Draft 23: October 4December 11, 2013 

None. 

Moderate VSL 

None. 

High VSL 
Each Transmission 
Service Provider that 
uses the Flowgate 
Methodology did not 
use the AFC 
determined by the 
Transmission Service 
Provider for reliability‐
related constraints 
identified in part 1.3. 
(2.2) 
None. 

Severe VSL 
determining AFC or 
ATC values in its 
ATCID. 

Each Transmission 
Service Provider that 
uses determines CBM 
values did not develop 
a CBMID describing its 
method for 
determining CBM 
values. 

OR 

Each Transmission 
Service Provider that 
uses determines CBM 
values did not reflect 
its current practices 
for determining CBM 
values in its CBMID. 
Page 16 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R4 

Operations 
Planning 

Lower 

R5 

Operations 
Planning 

Lower 

Draft 23: October 4December 11, 2013 

None. 

Moderate VSL 
None. 

High VSL 

Severe VSL 

None. 

Each Transmission 
Operator that uses 
determines TRM 
values did not develop 
a TRMID describing its 
method for 
determining TRM 
values. 

OR 

Each Transmission 
Operator that uses 
determines TRM 
values did not reflect 
its current practices 
for determining TRM 
values in its TRMID. 
Each Transmission 
Each Transmission 
Each Transmission 
Each Transmission 
Operator or 
Operator or 
Operator or 
Operator or 
Transmission Service 
Transmission Service 
Transmission Service 
Transmission Service 
Provider did not 
Provider did not 
Provider failed to 
Provider did not 
respond in writing to a  respond in writing to a  respond in writing to a  respond in writing to a 
written request by one  written request by one  written request by one  written request by one 
or more of the 
or more of the 
or more of the 
or more of the 
registered entities 
registered entities 
registered entities 
registered entities 
specified in 
specified in 
specified in 
specified in 
Requirement R5 within  Requirement R5 within  Requirement R5 within  Requirement R5. 
45 calendar days from  76 calendar days from  106 calendar days 

Page 17 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

R # 

Time 
Horizon 

VRF 

Violation Severity Levels (VSLs) 
Lower VSL 

R6 

Operations 
Planning 

Lower 

Draft 23: October 4December 11, 2013 

the date of the 
request, but did 
respond in writing 
within 75 calendar 
days. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respond to a written 
request for data by 
one or more of the 
registered entities 
specified in 
Requirement R6 by 
making the requested 
data available within in 
45 calendar days from 
the date of the 
request, but did 
respond within 75 
calendar days. 

Moderate VSL 
the date of the 
request, but did 
respond in writing 
within 105 calendar 
days. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respond to a written 
request for data by 
one or more of the 
registered entities 
specified in 
Requirement R6 by 
making data available 
within 76 calendar 
days from the date of 
the request, but did 
respond within 105 
calendar days. 

High VSL 
from the date of the 
request, but did 
respond in writing 
within 135 calendar 
days. 
Each Transmission 
Operator or 
Transmission Service 
Provider did not 
respond to a written 
request by one or 
more of the registered 
entities specified in 
Requirement R6 by 
making data available 
within 106 calendar 
days from the date of 
the request, but did 
respond within 135 
calendar days. 

Severe VSL 

Each Transmission 
Operator or 
Transmission Service 
Provider failed to 
respond to a written 
request for data by 
making data available 
to one or more of the 
entities specified in 
Requirement R6. 

Page 18 of 20 

MOD‐001‐2 — Modeling, Data, and Analysis — Available Transmission System Capability 

D. Regional Variances

None. 
E. Interpretations

None. 
F. Associated Documents

None. 

Draft 23: October 4December 11, 2013 

Page 19 of 20 

Application Guidelines 
Guidelines and Technical Basis
Please see the MOD A White Paper for further information regarding the technical basis for 
each requirement.

Draft 23: October 4December 11, 2013 

Page 20 of 20 

Implementation Plan
Project 2012-05 MOD A
Implementation Plan for MOD-001-2 – Available Transmission System Capability
Approvals Required
MOD-001-2 – Available Transmission System Capability
Prerequisite Approvals
There are no other standards that must receive approval prior to the approval of this standard.
Revisions to Glossary Terms
None
Applicable Entities
Transmission Operator
Transmission Service Provider
Applicable Facilities
N/A
Conforming Changes to Other Standards
None
Effective Dates
The standard shall become effective on the first day of the first calendar quarter that is 18 months
after the date that the standard is approved by an applicable governmental authority or as otherwise
provided for in a jurisdiction where approval by an applicable governmental authority is required for a
standard to go into effect. Where approval by an applicable governmental authority is not required,
the standard shall become effective on the first day of the first calendar quarter that is 18 months after
the date the standard is adopted by the NERC Board of Trustees or as otherwise provided for in that
jurisdiction.
Justification
The proposed 18-month implementation period is designed to allow the North American Energy
Standards Board (NAESB) to include in its Wholesale Electric Quadrant Standards for Business Practices
and Communication Protocols for Public Utilities (WEQ Standards), prior to the effective date of

proposed MOD-001-2 and the retirement of currently effective Reliability Standards MOD-001-1, MOD004-1, MOD-008-1, MOD-028-2, MOD-029-1a and MOD-030-2 (MOD A Standards), those elements
from the MOD A Standards that relate to commercial or business practices and are not included in
proposed MOD-001-2. NERC and the standard drafting team recognize that even though certain of the
requirements in the MOD A Standards do not address reliability issues and, in turn, are not included in
proposed MOD-001-2, those requirements may be essential for market or commercial purposes and
should be considered by an organization, like NAESB, that administers business practice standards for
the electric industry.
The proposed implementation period should provide NAESB sufficient time, working through its
business practice development process, to adopt revised WEQ Standards to include the commercial
elements of the MOD A Standards and for the Federal Energy Regulatory Commission to incorporate by
reference the revised WEQ Standards into its regulations. NERC expects that NAESB will adopt revised
WEQ Standards to become effective on the same date as the proposed MOD-001-2 and the retirement
of the MOD A Standards will become effective.
Retirements
MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and MOD-030-2 shall be retired at
midnight of the day immediately prior to the effective date of MOD-001-2. The effective retirement
date should coincide with the effective date of revised WEQ Standards adopted by NAESB.

Project 2012-05 ATC Revisions
October 4, 2013

2

Compliance Operations

Draft Reliability Standard Compliance Guidance for MOD-001-2
October 21, 2013
Introduction
The NERC Compliance department (Compliance) worked with the MOD A standard drafting team (SDT) to review
the proposed standard MOD-001-2. The purpose of the review was to discuss the requirements of the proposed
standard to obtain an understanding of its intended purpose and the evidence necessary to support compliance.
The purpose of this document is to address specific questions posed by the MOD A SDT in order to aid in the
drafting of the requirements and provide a level of understanding regarding evidentiary support necessary to
demonstrate compliance.
While all compliance evaluations require levels of auditor judgment, participating in these reviews allows
Compliance to develop training and approaches to support a high level of consistency in audits conducted by the
Regional Entities. The following questions and answers are intended to assist the SDT in further refining the
standard and to serve as a resource in the development of training for auditors.
MOD-001-2 Questions
Question 1
In Requirements R1, R2, R3, and R4, what is meant by “current” practices and methodologies in determining
various values and what will an auditor need to see to meet the compliance aspects of the requirements?
Compliance Response to Question 1
With regards to “current” practices, the auditor will focus on the last determined value for each requirement and
the method the entity used to determine that value. The auditor may also ask for a forward looking demonstration
of the value to determine that the registered entity follows its methodology to determine the given value.

Question 2
How will an auditor verify whether a Transmission Operator determines TFC or TTC values (R1) or that a
Transmission Service Provider determines AFC or ATC values (R2)?
Compliance Response to Question 2
Although a registered entity may meet the registration criteria to be registered as a Transmission Operator, there
are instances where that Transmission Operator does not determine TFC or TTC values. Similarly, a registered entity
may meet the registration criteria to be registered as a Transmission Service Provider, there are instances where
that Transmission Service Provider does not determine AFC or ATC. In these instances, as the registered entity does
not determine these values, it would therefore not be unable to fulfill the requirements.
An auditor will first come to an understanding of how the entity operates and whether they determine TFC or TTC.
In the event that it is clear to the auditor that the entity does not determine TFC or TTC, this will be sufficient
evidence for the auditor that the appropriate requirements are not applicable to that entity. In the event that it is
less clear, the auditor will look to see whether the entity operates facilities that are used by a Transmission Service

Provider for transmission service or a monitored path or Flowgate elements to establish whether the requirement
is applicable. If questions remain after this verification, the auditor could look to neighboring entities for
confirmation.
Question 3
Originally, the MOD A ad hoc group included clauses within Requirements R3 and R4 for those registered entities
that do not determine CBM or TRM to state that within its CBMID or TRMID. In consideration of comments, the SDT
removed that language as it met the Paragraph 81 criteria of an administrative burden. Therefore, how will an
auditor verify that those registered entities do not determine CBM or TRM?
Compliance Response to Question 3
An auditor will be looking for an attestation that the registered entity does not determine CBM (R3) or TRM (R4)
and may further look into the registered entity’s ATC equations for previous determined values to see that CBM or
TRM values are not determined.
This approach to compliance assessment is supported in FERC Order 729 at P 298, FERC stated, “though MOD-004-1
[CBM] is not as explicit with regard to its applicability, we believe that its applicability is implicitly reserved to those
entities that maintain capacity benefit margin. Thus, it does not appear that Entergy, or any other entity, would be
in violation of MOD-004-1 [CBM] or MOD-008-1 [TRM] if it does not maintain transmission reliability margin or
capacity benefit margin.”
Conclusion
Following final approval of the Reliability Standard, Compliance will develop the final Reliability Standards Auditor
Worksheet (RSAW) and associated training. Attachment A represents the version of the proposed standard
requirements referenced in this document.

Draft Reliability Standard Compliance Guidance for MOD-001-2
October 21, 2013

2

Standards Authorization Request Form
When completed, please email this form to:

[email protected]

NERC welcomes suggestions to improve the
reliability of the bulk power system through
improved reliability standards. Please use this form
to submit your request to propose a new or a
revision to a NERC’s Reliability Standard.

Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard:

Available Transmission System Capability

Date Submitted:

Revised: September 25, 2013
Original: July 3, 2013

SAR Requester Information
Name:

Ryan Stewart

Organization:

NERC

Telephone:

404-446-2569

E-mail:

[email protected]

SAR Type (Check as many as applicable)
New Standard

Withdrawal of existing Standard

Revision to existing Standard

Urgent Action

SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
The industry need is to resolve FERC directives, incorporate lessons learned, update standards, and to
incorporate initiatives such as results-based, Paragraph 81, etc. The industry is also reviewing the
assessments and recommendations of the Independent Experts Review Panel in support of
transforming the existing set of NERC Reliability Standards to steady-state.

Standards Authorization Request Form

SAR Information
Purpose or Goal (How does this request propose to address the problem described above?):
The SAR proposed modifying standards MOD-001, MOD-004, MOD-008, MOD-028, MOD-029, and
MOD-030 by combining them into one standard by consolidating the reliability components of the
existing standards, retiring the administrative components and transferring market-based requirements
out of the NERC Reliability Standards.
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
The objectives are to address the outstanding directives from FERC Order 729, remove administrative
and market-based requirements from the requirements, and, as possible, incorporate lessons learned.
Lessons learned include best practices by entities, compliance audit experiences with regard to clear
requirements and measures, and growth and maturity in the methods for determining Total Transfer
Capability (TTC), Total Flowgate Capability (TFC), Transmission Reliability Margin (TRM), Capacity Benefit
Margin (CBM), Available Transfer Capability (ATC) and Available Flowgate Capability (AFC).
Brief Description (Provide a paragraph that describes the scope of this standard action.)
Develop a single standard that consolidates the existing MOD-001-1a, MOD-004-1, MOD-008-1, MOD028-1, MOD-029-1a, and MOD-030-2 into a single standard that covers the reliability-related impact of
ATC and AFC calculations, such as the need for Transmission Service Providers to implement their ATC
or AFC calculations in a consistent manner and share ATC or AFC data with their neighboring
Transmission Service Providers or other entities who need such data for reliability purposes.
The requirements are placed within a new version of MOD-001 (MOD-001-2).
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
Detailed description of this project can be found in the Technical White Paper of the original SAR
submittal package.
NERC is working with the North American Energy Standards Board (NAESB) to affect a transfer of the
requirements in the currently effective Reliability Standards MOD-001-1, MOD-004-1, MOD-008-1,

Project 2012-05 Standards Authorization Request
September 25, 2013

2

Standards Authorization Request Form

SAR Information
MOD-028-2, MOD-029-1a and MOD-030-2 (i.e., the MOD A Standards) that are not included in
proposed MOD-001-2 to NAESB to be reviewed for possible inclusion in NAESB’s business practice
standards. NERC and the Project 2012-05 ATC Revisions standard drafting team recognize that even if
certain requirements in the existing MOD A Standards do not address reliability issues and, in turn, are
not included in proposed MOD-001-2, those requirements or components within them may be essential
for market or competition purposes and should be transitioned to an organization that focuses on
market-based standards. Given its role in developing commercial business practices for the electricity
industry, NAESB is likely to be selected by FERC as the appropriate organization to review the
requirements in the currently effective MOD A Standards that are not included in proposed MOD-001-2.

Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization

Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.

Interchange Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads
within a Planning Coordinator area.

Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.

Project 2012-05 Standards Authorization Request
September 25, 2013

3

Standards Authorization Request Form

Reliability Functions
Transmission Service
Provider

Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).

Transmission Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling
Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market Operator

Interface point for reliability functions with commercial functions.

Load-Serving Entity

Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.

Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.

Project 2012-05 Standards Authorization Request
September 25, 2013

4

Standards Authorization Request Form

Reliability and Market Interface Principles
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
Yes
Yes
Yes

Yes

Related Standards
Standard No.

Explanation

MOD-001-1a

Available Transmission System Capability

MOD-004-1

Capacity Benefit Margin

MOD-008-1

Transmission Reliability Margin Calculation Methodology

MOD-028-1

Area Interchange Methodology

MOD-029-1a

Rated System Path Methodology

MOD-030-2

Flowgate Methodology

Related SARs
SAR ID

Explanation

Project 2012-05 Standards Authorization Request
September 25, 2013

5

Standards Authorization Request Form

Related SARs

Regional Variances
Region

Explanation

ERCOT

FERC Order No. 729 at P 298 states: “…it is appropriate to exempt entities within ERCOT from
complying with these Reliability Standards. We agree that, due to physical differences of
ERCOT’s transmission system, the MOD Reliability Standards approved herein would not
provide any reliability benefit within ERCOT.”

FRCC

None

MRO

None

NPCC

None

RFC

None

SERC

None

SPP

None

WECC

None

Project 2012-05 Standards Authorization Request
September 25, 2013

6

Standards Authorization Request Form
When completed, please email this form to:

[email protected]

NERC welcomes suggestions to improve the
reliability of the bulk power system through
improved reliability standards. Please use this form
to submit your request to propose a new or a
revision to a NERC’s Reliability Standard.

Request to propose a new or a revision to a Reliability Standard
Title of Proposed Standard:

Available Transmission System Capability

Date Submitted:

July 3Original: July 3, 2013
Revised: September 25, 2013

SAR Requester Information
Name:

Ryan Stewart

Organization:

NERC

Telephone:

404-446-2569

E-mail:

[email protected]

SAR Type (Check as many as applicable)
New Standard

Withdrawal of existing Standard

Revision to existing Standard

Urgent Action

SAR Information
Industry Need (What is the industry problem this request is trying to solve?):
Resolve The industry need is to resolve FERC directives, incorporate lessons learned, update standards,
and to incorporate ERO initiatives, including drafting such as results-based ,or, performance-based,
standards consistent with Paragraph 81 , etcriteria. The industry need is to also reviewing the
assessments and recommendations of the Independent Experts Review Panel in support of
transforming the existing set of NERC Reliability Standards into steady-state. The industry reliability
need is to ensure that determinations of available transfer capability are accomplished in a manner that

SAR Information
supports the reliable operation of the Bulk Power System, etc.
Purpose or Goal (How does this request propose to address the problem described above?):
The pro forma standardSAR proposeds (1) modifying standards MOD-001, MOD-004, MOD-008, MOD028, MOD-029, and MOD-030 by cominingconsolidating them into onea single standard by consolidates
consolidatingfocused exclusively on the reliability components of the existing standards and retires (2)
transferring the market-based requirements to another organization, like NAESB, that administers
business practice standards for the electric industry.
Identify the Objectives of the proposed standard’s requirements (What specific reliability deliverables
are required to achieve the goal?):
The objectives are to address the outstanding directives from FERC Order 729, remove market-based
requirements from the requirements, and incorporate lessons learned. Lessons learned include best
practices by entities, sharing of those best practices, compliance audit experiences, and growth and
maturity of the markets. As noted above, the objective is to draft a standard that helps ensure that
determinations of available transfer capability are accomplished in a manner that supports the reliable
operation of the Bulk Power System.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
An informal development ad hoc group is presenting a pro forma standard thatThis project will address
the consolidates consolidatation of the existing standards MOD-001-1a, MOD-004-1, MOD-008-1, MOD028-1, MOD-029-1a, and MOD-030-2 into a single standard that covers the reliability-related impact of
Available Transfer Capability (ATC) and Available Flowgate Capability (AFC) calculations, such as the
need for Transmission Service Providers to implement their ATC or AFC calculations in a consistent
manner and share ATC or AFC data with their neighboring Transmission Service Providers or other
entities who need such data for reliability purposes.
The pro forma standard requirements are placed within a new version of MOD-001 (MOD-001-2).
Detailed Description (Provide a description of the proposed project with sufficient details for the
standard drafting team to execute the SAR. Also provide a justification for the development or revision
of the standard, including an assessment of the reliability and market interface impacts of implementing
or not implementing the standard action.)
Detailed description of this project can be found in the Technical White Paper of thisprovided in the
initial SAR submittal package.

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

2

SAR Information
NERC is working with the North American Energy Standards Board (NAESB) to affect a transfer of the
requirements in currently effective Reliability Standards MOD-001-1, MOD-004-1, MOD-008-1, MOD028-2, MOD-029-1a and MOD-030-2 (i.e., the MOD A Standards) that are not included in proposed
MOD-001-2 to NAESB to be reviewed for possible inclusion in NAESB’s business practice standards.
NERC and the Project 2012-05 ATC Revisions standard drafting team recognize that even if certain
requirements in the existing MOD A Standards do not address reliability issues and, in turn, are not
included in proposed MOD-001-2, those requirements or components within them may be essential for
market or competition purposes and should be transitioned to an organization that focuses on marketbased standards. Given its role in developing commercial business practices for the electricity industry,
NAESB is likely to be the appropriate organization to review the requirements in the currently effective
MOD A Standards that are not included in proposed MOD-001-2. [consider moving this up to objectives
section]

Reliability Functions
The Standard will Apply to the Following Functions (Check each one that applies.)
Regional Reliability
Organization

Conducts the regional activities related to planning and operations, and
coordinates activities of Responsible Entities to secure the reliability of
the Bulk Electric System within the region and adjacent regions.

Reliability Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area and
supports Interconnection frequency in real time.

Interchange Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority Areas.

Planning Coordinator

Assesses the longer-term reliability of its Planning Coordinator Area.

Resource Planner

Develops a >one year plan for the resource adequacy of its specific loads

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

3

Reliability Functions
within a Planning Coordinator area.
Transmission Planner

Develops a >one year plan for the reliability of the interconnected Bulk
Electric System within its portion of the Planning Coordinator area.

Transmission Service
Provider

Administers the transmission tariff and provides transmission services
under applicable transmission service agreements (e.g., the pro forma
tariff).

Transmission Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission assets
within a Transmission Operator Area.

Distribution Provider

Delivers electrical energy to the End-use customer.

Generator Owner

Owns and maintains generation facilities.

Generator Operator

Operates generation unit(s) to provide real and reactive power.

Purchasing-Selling
Entity

Purchases or sells energy, capacity, and necessary reliability-related
services as required.

Market Operator

Interface point for reliability functions with commercial functions.

Load-Serving Entity

Secures energy and transmission service (and reliability-related services)
to serve the End-use Customer.

Reliability and Market Interface Principles
Applicable Reliability Principles (Check all that apply).
1. Interconnected bulk power systems shall be planned and operated in a coordinated manner
to perform reliably under normal and abnormal conditions as defined in the NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled within
defined limits through the balancing of real and reactive power supply and demand.
3. Information necessary for the planning and operation of interconnected bulk power systems
shall be made available to those entities responsible for planning and operating the systems
reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power systems
shall be developed, coordinated, maintained and implemented.

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

4

Reliability and Market Interface Principles
5. Facilities for communication, monitoring and control shall be provided, used and maintained
for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems shall be
trained, qualified, and have the responsibility and authority to implement actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored and
maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.
Does the proposed Standard comply with all of the following Market Interface
Principles?
1. A reliability standard shall not give any market participant an unfair competitive
advantage.
2. A reliability standard shall neither mandate nor prohibit any specific market
structure.
3. A reliability standard shall not preclude market solutions to achieving compliance
with that standard.
4. A reliability standard shall not require the public disclosure of commercially
sensitive information. All market participants shall have equal opportunity to
access commercially non-sensitive information that is required for compliance
with reliability standards.

Enter
(yes/no)
Yes
Yes
Yes

Yes

Related Standards
Standard No.

Explanation

MOD-001-1a

Available Transmission System Capability

MOD-004-1

Capacity Benefit Margin

MOD-008-1

Transmission Reliability Margin Calculation Methodology

MOD-028-1

Area Interchange Methodology

MOD-029-1a

Rated System Path Methodology

MOD-030-2

Flowgate Methodology

Related SARs

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

5

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

ERCOT

FERC Order 729 states, in Paragraph 298, “…it is appropriate to exempt entities within ERCOT
from complying with these Reliability Standards. We agree that, due to physical differences of
ERCOT’s transmission system, the MOD Reliability Standards approved herein would not
provide any reliability benefit within ERCOT.”

FRCC

None

MRO

None

NPCC

None

RFC

None

SERC

None

SPP

None

WECC

None

Project 2012-05 Standards Authorization Request
September 25July 3, 2013

6

Project 2012-05 Mapping Document

Transition of MOD-001-1a, MOD-004-1, MOD-008-1, MOD-028-1, MOD-029-1a, and
MOD-030-2 to Proposed MOD-001-2
The below mapping document provides information on how the approved requirements within MOD-001-a, MOD-004-1, MOD-008-1,
MOD-028-1, MOD-029-1a, and MOD-030-2 transition into the proposed MOD-001-1. As a general statement, the reliability-based
components of those Reliability Standards are captured in MOD-001-2 while non-reliability-based components will be transition out of the
NERC Reliability Standards. Where a prescriptive existing requirement does not easily map into the proposed MOD-001-2, a description and
change justification is provided.

Requirement in
Approved Standard

MOD-001-1a R1

MOD-001-1a R2
MOD-001-1a R2.1
MOD-001-1a R2.2
MOD-001-1a R2.3

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed Reliability Standard requires disclosure of the method
used to calculate Available Transfer Capability (ATC) but no longer
Requirement R2
requires a registered entity to select a method explicitly described in
the NERC Reliability Standards.
The proposed Reliability Standard will require disclosure of calculation
Requirement R2
frequency but does not specify the range of required calculations.
Requirement R2
See comments on Requirement R2.
Requirement R2
See comments on Requirement R2.
Requirement R2
See comments on Requirement R2.

Requirement in
Approved Standard

MOD-001-1a R3

MOD-001-1a R3.1
MOD-001-1a R3.2
MOD-001-1a R3.2.1
MOD-001-1a R3.2.2
MOD-001-1a R3.3

MOD-001-1a R3.4

MOD-001-1a R3.5
MOD-001-1a R3.6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R2 of the proposed Reliability Standard retains the
obligation to have an Available Transfer Capability Implementation
Requirement R2
Document (ATCID) that reflects its method for calculating Available
Flowgate Capability (AFC) or ATC.
This information would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirements R2 & R5
Requirement R2 and may be addressed under Requirement R5 in
response to a request for clarification.
This rationale would be included within the ATCID created under
Requirement R2
Requirement R2.
This information would be included within the ATCID created under
Requirement R2
Requirement R2.
The identity of the TSPs and Transmission Operators (TOPs) for which it
provides data is captured when a registered entity formally requests
Requirements R5 &R6.
that information under Requirements R5 or R6 of the proposed
Reliability Standard.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.

2

Requirement in
Approved Standard
MOD-001-1a R3.6.1
MOD-001-1a R3.6.2
MOD-001-1a R3.6.3
MOD-001-1a R4
MOD-001-1a R4.1
MOD-001-1a R4.2
MOD-001-1a R4.3
MOD-001-1a R4.4
MOD-001-1a R4.5
MOD-001-1a R4.6
MOD-001-1a R5

MOD-001-1a R6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
This description would be included within the ATCID created under
Requirement R2
Requirement R2.
The requirement for a Transmission Service Provider (TSP) to notify
registered entities when a change is made to its ATCID is an
administrative burden and provides little to no reliability benefit.
Requirement R5
Posting on its company website or Open Access Same-Time
Information System (OASIS) provides notice that a change has been
made. Although not specifically required under the proposed Reliability
Standards, a registered entity may continue to provide such notice.
Requirement R5 of the proposed Reliability Standard obligates the TSP
Requirement R5 for an ATCID provided upon
to provide its ATCID to any registered entity that needs it for reliability
formal request.
upon request.
Ensuring that ATC, Total Transfer Capability (TTC), Available Flowgate
Capability (AFC), and Total Flowgate Capability (TFC) calculations use
assumptions no more limiting than those used in the planning of
The Requirement has been retired.
operations does not serve a clear reliability goal. The ATCID will have a
description of how ATC, TTC, AFC, or TFC is calculated, with sufficient
detail to allow for a comparison.

3

Requirement in
Approved Standard

MOD-001-1a R7

MOD-001-1a R8
MOD-001-1a R8.1
MOD-001-1a R8.2
MOD-001-1a R8.3
MOD-001-1a R9
MOD-001-1a R9.1
MOD-001-1a R9.1.1
MOD-001-1a R9.1.2
MOD-001-1a R9.1.3
MOD-001-1a R9.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-001-1a – Available Transmission System Capability
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Ensuring that ATC, TTC, AFC, and TFC calculations use assumptions no
more limiting then those used in the planning of operations does not
The Requirement has been retired.
serve a clear reliability goal. The ATCID will have a description of how
ATC, TTC, AFC, or TFC is calculated, with sufficient detail to allow for a
comparison.
The reliability component of ATC is disclosure of a registered entity’s
practice which is still captured, but not the performance aspect of the
The Requirement has been retired.
ATC calculations. Mandating the frequency with which ATC is
calculated does not serve a reliability benefit.
The Requirement has been retired.
See comments on Requirement R8.
The Requirement has been retired.
See comments on Requirement R8.
The Requirement has been retired.
See comments on Requirement R8.
Requirement R6 of the proposed Reliability Standard requires a TOP or
TSP, within 45 calendar days of receiving a written request, to make
available the data or explain why it is not doing so due to
confidentiality, regulatory, or security concerns.
See comments for Requirement R9.
Requirement R5
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.
See comments for Requirement R9.

4

Requirement in
Approved Standard

MOD-004-1 R1
MOD-004-1 R1.1
MOD-004-1 R1.2
MOD-004-1 R1.3
MOD-004-1 R2

MOD-004-1 R3
MOD-004-1 R3.1
MOD-004-1 R3.2
MOD-004-1 R4
MOD-004-1 R4.1
MOD-004-1 R4.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed standard will require registered entities that use Capacity
Benefit Margin (CBM) to have a Capacity Benefit Margin (CBMID) that
Requirement R3
reflects its current practices for determining CBM. The proposed
Reliability Standard does not dictate how CBM must be calculated.
Requirement R3
See comments above.
Requirement R3
See comments above.
Requirement R3
See comments above.
Requirement R5 of the proposed Reliability Standard requires TSPs to
Requirement part R5.2.2
share its CBMID with entities that request it and have a reliability need
for that data.
The applicability of the proposed Reliability Standard has been changed
so that the LSE is not an applicable registered entity within the
Requirement R3
Reliability Standard. The method by which a TSP determines CBM will
be included in its CBMID.
Requirement R3
See comment above.
Requirement R3
See comment above.
The applicability of the proposed Reliability Standard has been changed
so that the Resource Planner (RP) is not an applicable registered entity
The Requirement has been retired.
within the Reliability Standard. The method by which a TSP determines
CBM will be included in its CBMID.
The Requirement has been retired.
See comment above.
The Requirement has been retired.
See comment above.

5

Requirement in
Approved Standard
MOD-004-1 R5
MOD-004-1 R5.1
MOD-004-1 R5.2

MOD-004-1 R6
MOD-004-1 R6.1
MOD-004-1 R6.2

MOD-004-1 R7

MOD-004-1 R8

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The proposed Reliability Standard will require TSPs that use CBM to
Requirement R3
have a CBMID but does not specify what must be included or how it is
calculated.
The proposed standard will require TSPs that use CBM to have a CBMID
Requirement R3
but does not specify what must be included or how it is calculated.
The proposed standard will require TSPs that use CBM to have a CBMID
Requirement R3
but does not specify what must be included or how it is calculated.
The applicability of the proposed standard has been changed so that
the Transmission Planner (TP) is not an applicable registered entity
The Requirement has been retired.
within the standard. The method by which a TSP determines CBM will
be included in its CBMID.
The Requirement has been retired.
See comment above.
The Requirement has been retired.
See comment above.
The proposed standard does not explicitly require that the TSP to notify
Load-Serving Entities (LSEs) and RPs of the amount of CBM set aside.
The SDT determined this requirement provided little to no reliability
The Requirement has been retired.
benefit. The proposed Reliability Standard only requires the TSP to have
a CBMID and make that available to other registered entities, including
LSEs and RPs.
The applicability of the proposed Reliability Standard has been changed
The Requirement has been retired.
so that the TP is not an applicable registered entity within the Reliability
Standard.

6

Requirement in
Approved Standard
MOD-004-1 R9
MOD-004-1 R9.1
MOD-004-1 R9.2
MOD-004-1 R10

MOD-004-1 R11

MOD-004-1 R12

MOD-004-1 R12.1

MOD-004-1 R12.2

MOD-004-1 R12.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-004-1 – Capacity Benefit Margin
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The new Requirement R6 requires TSPs to share the data used in CBM
Requirement R6
calculations with registered entities that have a reliability need for that
data. TPs are not longer subject to the Reliability Standard.
Requirement R6
See comment above.
Requirement R6
See comment above.
The applicability of the proposed Reliability Standard has been changed
The Requirement has been retired.
so that the LSE or Balancing Authority (BA) are not applicable registered
entities within the Reliability Standard.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.
The proposed Reliability Standard will require entities that use CBM to
Requirement R3
have a CBMID but does not dictate what must be included or how it is
calculated.

7

Requirement in
Approved Standard
MOD-008-1 R1

MOD-008-1 R1.1
MOD-008-1 R1.2
MOD-008-1 R1.3
MOD-008-1 R1.3.1
MOD-008-1 R1.3.2
MOD-008-1 R1.3.3
MOD-008-1 R2

MOD-008-1 R3
MOD-008-1 R4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R4
Requirement R4 requires a TRMID that reflects the TOPs current
practices for determining TRM. The proposed Reliability Standard does
not dictate how TRM must be calculated as such detail provides little to
no reliability benefit.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4
See comment above.
Requirement R4 requires a TRMID that describes how TRM values are
determined. Prescribing that the value must come from a predefined
Requirement R4
list of uncertainties or that the value does not double count with CBM
does not provide any reliability benefit.
Requirements R5 and R6 require disclosure of TRMID and underlying
Requirement R5
data upon request if not already posted on OASIS or similar site.
Requirement R4 requires a TRMID that includes the frequency of
Requirement R4
updating; setting an arbitrary date to recalculate TRM does not
contribute to reliability.

8

Requirement in
Approved Standard

MOD-008-1 R5

Requirement in
Approved Standard

MOD-028-1 R1

MOD-028-1 R1.1
MOD-028-1 R1.2
MOD-028-1 R1.3
MOD-028-1 R1.4
MOD-028-1 R1.5
MOD-028-1 R1.5.1
MOD-028-1 R1.5.2
MOD-028-1 R1.5.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-008-1 – Transmission Reliability Margin Calculation Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R2 and R4, the ATCID and TRMID respectively, would
contain information on how the value is shared and on what frequency.
Requirements R2 & R4
Setting an arbitrary frequency is unnecessary to meet the reliability
goal of disclosure.

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1 requires a TOP to have a written methodology for
determining TTC or TFC. Requirement R2 requires a TSP to have an
Requirements R1 & R2
ATCID that describes how ATC or AFC is determined, which would
include any parts of the TTC/TFC development not covered by a TOP
under Requirement R1.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

9

Requirement in
Approved Standard
MOD-028-1 R1.5.4
MOD-028-1 R2

MOD-028-1 R2.1

MOD-028-1 R2.2

MOD-028-1 R2.3

MOD-028-1 R3

MOD-028-1 R3.1
MOD-028-1 R3.1.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
Requirements R1 & R2
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice that meets the reliability need of this
Requirements R1 & R2
requirement; further specification or instructions on how to perform
this task do not address the reliability goal of disclosure.
Requirements R1 and R2 require disclosure by the TOP and TSP
respectively of their practice. In addition, R1 requires the TOP to use
Requirements R1 & R2
the defined facility ratings and SOL's, as appropriate, to determine the
TTC value.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1, Part 1.2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

10

Requirement in
Approved Standard
MOD-028-1 R3.1.2
MOD-028-1 R3.1.2
MOD-028-1 R3.2
MOD-028-1 R3.2.1
MOD-028-1 R3.2.2
MOD-028-1 R3.2.2
MOD-028-1 R4
MOD-028-1 R4.1

MOD-028-1 R4.2

MOD-028-1 R4.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 set this obligation upon the TOP and TSP,
Requirements R1 & R2
respectively.
Requirements R1 and R2 require disclosure of practice, which is the
reliability need for this requirement. Verification that a contract is being
Requirements R1 & R2
followed is primarily a commercial issue and not a NERC Reliability
issue.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and Requirement R1
specifically addresses documentation of their process and reliability
points. The remainder of the material in the requirement provides
Requirement R1, Part 1.2
instructions on determining TTC, which is not necessary within a NERC
requirement to protect reliability. The TTC methodology will describe
how these services are used and any necessary clarifications can be
sought under Requirement R5. Having a long list of methods of
incorporating these service did not contribute to reliability.

11

Requirement in
Approved Standard
MOD-028-1 R5

MOD-028-1 R5.1

MOD-028-1 R5.2
MOD-028-1 R5.3
MOD-028-1 R6

MOD-028-1 R6.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
calculation will be discussed within the ATCID and driven by either
Requirements R1 & R2
reliability or market needs, whichever provides for a tighter time frame.
The required periodicity of a TFC or TTC calculation is a method and
region specific issue, and it is not necessary to reliability to specify such
a value.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
Requirement R1 and Parts 1.1 and 1.2.1
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.

12

Requirement in
Approved Standard

MOD-028-1 R6.2

MOD-028-1 R6.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
Requirements R1, Part 1.2.1
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
calculating TTC does not support a reliability need.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
Requirements R1
calculating TTC does not support a reliability need. The new Reliability
Standard does not prevent "Sum of Facility Ratings" as a limit on the
path, however it does not prescribe it either. "Sum of Facility Ratings"
is a commercial concept; the reliability aspect was addressed in
determining the Incremental Transfer Capability (ITC).

13

Requirement in
Approved Standard

MOD-028-1 R6.4

MOD-028-1 R7

MOD-028-1 R7.1

MOD-028-1 R7.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, and R1 specifically
addresses documentation of their process and the reliability points. The
remainder of the material in the requirement provides instructions on
determining TTC; using a requirement to explain a method of
Requirements R1
calculating TTC does not support a reliability need. Contractual rights
imply there is already a contract and obligation in place, there is no
reliability benefit in NERC monitoring this contract. The Reliability
Standard does not prevent this from being a limit, but does not
prescribe it either
This requirement serves no direct purpose other than serving as a
Requirement R1
bridge to the requirement parts below.
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
Requirement R1 & R6
requirement addresses. The frequency of disclosure is set by
agreement with the TSP or other factors, and there is no reliability
benefit in setting an arbitrary frequency of providing the value.
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
Requirement R1 & R6
requirement addresses. The frequency of disclosure is set by
agreement with the TSP or other factors, and there is no reliability
benefit in setting an arbitrary frequency of providing the value.

14

Requirement in
Approved Standard

MOD-028-1 R8

MOD-028-1 R9

MOD-028-1 R10

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement is primarily a definition of what Existing Transfer
Commitments (ETC) is and does not provide for system reliability.
Breaking ETC into its component parts is a guide for determining ETC
This Requirement has been retired.
but does not establish a reliability requirement. Under their
agreements with which the transmission commitments are made the
registered entity is obligated to respect those commitments and there
is no need for NERC to monitor this commercial arrangement.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This Requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
Requirements R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This Requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that
Requirements R10 and R11 just provided additional educational
reference to ATC, but did not establish a reliability requirement.

15

Requirement in
Approved Standard

MOD-028-1 R11

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-028-1 – Area Interchange Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
and the NERC Glossary of Terms defines ATC. Beyond that
This Requirement has been retired.
Requirements R10 and R11 just provided additional educational
reference on what ATC was but did not establish a reliability
requirement.

16

Requirement in
Approved Standard
MOD-029-1a R1

MOD-029-1a R1.1

MOD-029-1a R1.1.1
MOD-029-1a R1.1.1.1
MOD-029-1a R1.1.1.2
MOD-029-1a R1.1.1.3
MOD-029-1a R1.1.2
MOD-029-1a R1.1.3
MOD-029-1a R1.1.4
MOD-029-1a R1.1.5
MOD-029-1a R1.1.6
MOD-029-1a R1.1.7
MOD-029-1a R1.1.8
MOD-029-1a R1.1.9
MOD-029-1a R1.1.10

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirements R1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.

17

Requirement in
Approved Standard
MOD-029-1a R1.2
MOD-029-1a R2

MOD-029-1a R2.1

MOD-029-1a R2.1.1

MOD-029-1a R2.1.2

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Part 1.1 describes the method used to account for
Requirement R1, Part 1.1
Facility Ratings as well as system voltage, transient stability, voltage
stability, and other SOLs.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1, Part 1.2, Requirement R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
Requirement R1 specifically requires the TOP to respect transmission
element ratings, Requirements R1 and R2 requires disclosure of the
TOP and TSP's practices in this regard. The revised Reliability Standard
does not go into detail to require that the starting case for an analysis
Requirement R1, Parts 1.1 & 1.2,
meet these criteria. Requirement R1, Part 1.1 requires that TTC
Requirement R2
accounts for these elements, but does not require that the starting case
meet the criteria described under MOD-029 Requirement R2, Part 2.1.
Trying to list this detail would require a textbook level description of
the process and would not set a reliability goal.
Requirement R1, Parts 1.1 & 1.2,
See comment above.
Requirement R2

18

Requirement in
Approved Standard
MOD-029-1a R2.1.3

MOD-029-1a R2.2

MOD-029-1a R2.3

MOD-029-1a R2.4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Parts 1.1 & 1.2,
See comment above.
Requirement R2
This is not a reliability requirement but a business practice to provide
for some sort of result when a reliability constraint can't be reached.
This requirement part has been retired.
This level of information is appropriate in an instructional context but is
not a reliability requirement. The current Requirement R1 requires the
TOP to describe how it does this, but does not prescribe a method.
As the name implies, there is already an obligation between the parties
to respect a value and Requirement R1 just requires that TTC not
Requirements R1 & R2
exceed reliability limits, it does not rule out a lower limit due to
contractual obligations. There is no reliability benefit to NERC
monitoring to ensure that contractual obligations are met.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
This requirement part has been retired
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.

19

Requirement in
Approved Standard

MOD-029-1a R2.5

MOD-029-1a R2.6

MOD-029-1a R2.7

MOD-029-1a R2.8

MOD-029-1a R3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
This requirement part has been retired.
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
As the name implies, there is already an obligation between the parties
to respect a value and Requirement R1 just requires that TTC not
Requirements R1 & R2
exceed reliability limits, it does not rule out a lower limit due to
contractual obligations. There is no reliability benefit to NERC
monitoring to ensure that contractual obligations are met.
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
Requirements R1 & R2
R1. The remainder of the material in the requirement provides
instructions on determining TTC; using a requirement to explain a
method of calculating TTC does not support a reliability need.
Requirements R1 and R2 address this need by requiring a methodology,
Requirements R1 & R2
and in the effort to demonstrate that the methodology was followed
the necessary reports will be developed.
Requirement R1, Part 1.1 requires that SOLs be accounted for in the
Requirements R1 & R2
method used in determining TTC. Requirement R2 requires disclosure
of practices for determining ATC.

20

Requirement in
Approved Standard

MOD-029-1a R4

MOD-029-1a R5

MOD-029-1a R6

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1 of the proposed Reliability Standard requires
disclosure of the frequency of update, which is the reliability need this
requirement addresses. The frequency of disclosure is set by
agreement with the TSP considering individual facts and circumstances,
Requirements R1, R5, & R6
and there is no reliability benefit in setting an arbitrary frequency of
providing the value. Requirement R6 requires disclosure of data and
Requirement R5 requires disclosure of methods and responding to
requests for clarification.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.

21

Requirement in
Approved Standard

MOD-029-1a R7

MOD-029-1a R8

Requirement in
Approved Standard
MOD-030-2 R1

MOD-030-2 R1.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-029-1a – Rated System Path Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R7 and R8 do not appear verbatim in the new Reliability
Standard; however, Requirement R2 will require disclosure and the
This requirement has been retired.
NERC Glossary of Terms defines ATC. Beyond that Requirements R7 and
R8 just provided additional educational reference on what ATC was but
did not establish a reliability requirement.
Requirements R7 & R8 do not appear verbatim in the new Reliability
Standard; however, Requirement R2 will require disclosure and the
This requirement has been retired.
NERC Glossary of Terms defines ATC. Beyond that Requirements R7 and
R8 just provided additional educational reference on what ATC was but
did not establish a reliability requirement.
Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This is a summary of the requirement parts and does not in itself
Requirements R1 & R2
establish and obligation.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirement R1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.

22

Requirement in
Approved Standard
MOD-030-2 R1.2
MOD-030-2 R1.2.1
MOD-030-2 R1.2.2
MOD-030-2 R1.2.3
MOD-030-2 R1.2.4
MOD-030-2 R2
MOD-030-2 R2.1

MOD-030-2 R2.1.1

MOD-030-2 R2.1.1.1
MOD-030-2 R2.1.1.2
MOD-030-2 R2.1.1.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.
Requirement R1, Part 1.3 requires each methodology to describe the
process for including any reliability-related constraints requested to be
included by another TOP based on if the requesting TOP includes those
constraints in its TFC or TTC determination. Furthermore, Requirement
R1, Part 1.3.1 states that each TOP that uses the Flowgate methodology
Requirement R1, Parts 1.3 & 1.3.1
shall include in its methodology an impact test process for including
requested constraints. If a generator to Load transfer in a registered
entity’s area or a transfer to a neighboring registered entity impact the
requested constraint by five percent or greater, the requested
constraint shall be included in the TFC determination, otherwise the
requested constraint is not required to be included.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.

23

Requirement in
Approved Standard
MOD-030-2 R2.1.2
MOD-030-2 R2.1.2.1
MOD-030-2 R2.1.2.2
MOD-030-2 R2.1.2.3
MOD-030-2 R2.1.3
MOD-030-2 R2.1.4
MOD-030-2 R2.1.4.1
MOD-030-2 R2.1.4.2
MOD-030-2 R2.2
MOD-030-2 R2.3
MOD-030-2 R2.4

MOD-030-2 R2.5

MOD-030-2 R2.5.1

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
Requirement R1, Parts 1.3 & 1.3.1
See comment above.
This requirement part has been retired.
The required periodicity of updating a list is not of a reliability benefit.
This requirement part has been retired.
The required periodicity of updating a list is not of a reliability benefit.
Requirement R1, Part 1.1 requires that SOLs be accounted for in the
Requirement R1, Part 1.1 & Requirement R2 method used in determining TTC. Requirement R2 requires disclosure
of practices for determining ATC.
Requirements R1 and R2 require disclosure of practice which is the
reliability need for this requirement; the frequency or freshness of a
Requirements R1 & R2
calculation will be discussed within the ATCID and driven by either
reliability or market needs whichever provides for a tighter time frame.
The frequency of disclosure is set by agreement with the TSP
considering the individual facts and circumstances, and there is no
This requirement part has been retired.
reliability benefit in setting an arbitrary frequency of providing the
value.

24

Requirement in
Approved Standard

MOD-030-2 R2.6
MOD-030-2 R3
MOD-030-2 R3.1
MOD-030-2 R3.2
MOD-030-2 R3.3
MOD-030-2 R3.4
MOD-030-2 R3.5

MOD-030-2 R4

MOD-030-2 R5

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
The frequency of disclosure is set by agreement with the TSP
considering the individual facts and circumstances, and there is no
This requirement part has been retired.
reliability benefit in setting an arbitrary frequency of providing the
value.
Requirement R6
Requirement R6 requires data sharing.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R6
See comment above.
Requirement R1, Part 1.2 requires the use of these elements to the
extent that they impact the determination of TFC or TTC. These
requirements were modified to the list in Requirement R1, Part 1.2 and
Requirements R1, part 1.1 & R2
Requirement R2, Part 2.1 with the requirement that each methodology
shall describe the method used to account for the elements that impact
the determination of TFC, TTC, AFC or ATC.
This requirement serves no direct purpose other than serving as a
Requirements R1 & R2
bridge to the requirement parts below.

25

Requirement in
Approved Standard

MOD-030-2 R5.1

MOD-030-2 R5.2
MOD-030-2 R5.3

MOD-030-2 R6

MOD-030-2 R6.1
MOD-030-2 R6.1.1
MOD-030-2 R6.1.2
MOD-030-2 R6.2
MOD-030-2 R6.2.1
MOD-030-2 R6.2.2
MOD-030-2 R6.3
MOD-030-2 R6.4

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R1 and R2 maintain the reliability portion of these
requirements upon the TOP or TSP, respectively, including
documentation of their process and the reliability points addressed in
Requirements R1 & R2
R1. Specifically, Requirement R2, Part 2.2 requires each TSP that uses
the Flowgate Methodology to use the AFC determined by the TSP for
reliability constraints identified in Requirement R1, Part 1.3.
Requirements R1 & R2
See comment above.
Requirements R1 & R2
See comment above.
This requirement is primarily a definition of what ETC is and does not
provide for system reliability. Breaking ETC into its component parts is a
guide for determining ETC but does not establish a reliability
This requirement has been retired.
requirement. Under their agreements with which the transmission
commitments are made the registered entity is obligated to respect
those commitments and there is no need for NERC to monitor this
commercial arrangement.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.

26

Requirement in
Approved Standard
MOD-030-2 R6.5
MOD-030-2 R6.6
MOD-030-2 R6.7
MOD-030-2 R7
MOD-030-2 R7.1
MOD-030-2 R7.2
MOD-030-2 R7.3
MOD-030-2 R7.4
MOD-030-2 R7.5
MOD-030-2 R7.6
MOD-030-2 R7.7

MOD-030-2 R8

MOD-030-2 R9

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
This requirement part has been retired.
See comment above.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

27

Requirement in
Approved Standard

MOD-030-2 R10

MOD-030-2 R10.1

MOD-030-2 R10.2

MOD-030-2 R10.3

Project 2012-05 ATC Revisions
October 4, 2013

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
This requirement has been retired.
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
Requirement R2
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

28

Requirement in
Approved Standard

MOD-030-2 R11

Standard: MOD-030-2 – Flowgate Methodology
Reliability Components Transition to the
Below Requirement in New Standard or
Description and Change Justification
Other Action
Requirements R8, R9, R10 and R11 do not appear verbatim in the new
Reliability Standard; however, Requirement R2 will require disclosure
Requirement R2
and the NERC Glossary of Terms defines ATC. Beyond that these
requirements just provided additional educational reference on what
ATC was but did not establish a reliability requirement.

New Requirements not found in existing MOD standards
Requirement in
Transitions to the below Requirement in
Approved Standard
New Standard or Other Action
N/A
N/A

Project 2012-05 ATC Revisions
October 4, 2013

Description and Change Justification
N/A

29

Proposed Timeline for the
Project 2012-05 Standard Drafting Team (SDT)
Anticipated Date

Location

Event

July 11, 2013

-

SC Authorizes SAR

July 11, 2013

-

Conduct Nominations for Project 2012-05 SDT

July 11, 2013

-

Post SAR for 45-Day Initial Comment Period

August 16, 2013

-

Conduct Initial Ballot

August 26, 2013

-

45-Day Comment Period and Initial Ballot Closes

August 27-30, 2013

Colorado Springs,
Colorado

MOD A Standard Drafting Team Face to Face Meeting to
Respond to Initial Comments and Make Possible Revisions

October 4, 2013

-

Post Standard and Accompanying Materials for 45-day
Comment Period

November 8-18, 2013

-

Conduct Ballot

November 18, 2013

-

45-Day Comment Period and Ballot Closes

November 20-22, 2013

TBD

MOD A Standard Drafting Team Face to Face Meeting to
Respond to Ballot Period Comments

December 2-12, 2013

-

Conduct Final Ballot

December 2013

-

NERC Board of Trustees Adoption

December 31, 2013

-

NERC Files Petition with the Applicable Governmental
Authorities

DRAFT Reliability Standard Audit Worksheet1
MOD-001-2 – Modeling, Data, and Analysis – Available Transmission System
Capability
This section to be completed by the Compliance Enforcement Authority.
Audit ID:
Registered Entity:
NCR Number:
Compliance Enforcement Authority:
Compliance Assessment Date(s)2:
Compliance Monitoring Method:
Names of Auditors:

Audit ID if available; or REG-NCRnnnnn-YYYYMMDD
Registered name of entity being audited
NCRnnnnn
Region or NERC performing audit
Month DD, YYYY, to Month DD, YYYY
Audit
Supplied by CEA

Applicability of Requirements [RSAW developer to insert correct applicability]
BA
R1
R2
R3
R4
R5
R6

DP

GO

GOP

IA

LSE

PA

PSE

RC

RP

RSG

TO

TOP
3
X

TP

TSP
3

X
3
X
3

X
3
X
3
X

3

X
3
X

1

NERC developed this Reliability Standard Audit Worksheet (RSAW) language in order to facilitate NERC’s and the Regional Entities’ assessment of a registered
entity’s compliance with this Reliability Standard. The NERC RSAW language is written to specific versions of each NERC Reliability Standard. Entities using this RSAW
should choose the version of the RSAW applicable to the Reliability Standard being assessed. While the information included in this RSAW provides some of the
methodology that NERC has elected to use to assess compliance with the requirements of the Reliability Standard, this document should not be treated as a
substitute for the Reliability Standard or viewed as additional Reliability Standard requirements. In all cases, the Regional Entity should rely on the language
contained in the Reliability Standard itself, and not on the language contained in this RSAW, to determine compliance with the Reliability Standard. NERC’s Reliability
Standards can be found on NERC’s website. Additionally, NERC Reliability Standards are updated frequently, and this RSAW may not necessarily be updated with the
same frequency. Therefore, it is imperative that entities treat this RSAW as a reference document only, and not as a substitute or replacement for the Reliability
Standard. It is the responsibility of the registered entity to verify its compliance with the latest approved version of the Reliability Standards, by the applicable
governmental authority, relevant to its registration status.
The NERC RSAW language contained within this document provides a non-exclusive list, for informational purposes only, of examples of the types of evidence a
registered entity may produce or may be asked to produce to demonstrate compliance with the Reliability Standard. A registered entity’s adherence to the examples
contained within this RSAW does not necessarily constitute compliance with the applicable Reliability Standard, and NERC and the Regional Entity using this RSAW
reserves the right to request additional evidence from the registered entity that is not included in this RSAW. Additionally, this RSAW includes excerpts from FERC
Orders and other regulatory references. The FERC Order cites are provided for ease of reference only, and this document does not necessarily include all applicable
Order provisions. In the event of a discrepancy between FERC Orders, and the language included in this document, FERC Orders shall prevail.
2
3

Compliance Assessment Date(s): The date(s) the actual compliance assessment (on-site audit, off-site spot check, etc.) occurs.
Functional Entities operating within the Electric Reliability Council of Texas (ERCOT) are exempt from MOD-001-2.

Subject Matter Experts
Identify Subject Matter Expert(s) responsible for this Reliability Standard. (Insert additional rows if necessary)
Registered Entity Response (Required):
SME Name
Title

Organization

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

2

Requirement(s)

R1 Supporting Evidence and Documentation
R1.

Each Transmission Operator that determines Total Flowgate Capability (TFC) or Total Transfer
Capability (TTC) shall develop a written methodology (or methodologies) for determining TFC or TTC
values. The methodology (or methodologies) shall reflect the Transmission Operator’s current
practices for determining TFC or TTC values.
1.1 Each methodology shall describe the method used to account for the following limitations in
both the pre- and post-contingency state:
1.1.1

Facility ratings;

1.1.2

System voltage limits;

1.1.3

Transient stability limits;

1.1.4

Voltage stability limits; and

1.1.5

Other System Operating Limits (SOLs).

1.2 Each methodology shall describe the method used to account for each of the following
elements, provided such elements impact the determination of TFC or TTC:
1.2.1

The simulation of transfers performed through the adjustment of generation, Load, or
both;

1.2.2

Transmission topology, including, but not limited to, additions and retirements;

1.2.3

Expected transmission uses;

1.2.4

Planned outages;

1.2.5

Parallel path (loop flow) adjustments;

1.2.6

Load forecast; and

1.2.7

Generator dispatch, including, but not limited to, additions and retirements.

1.3 Each methodology shall describe the process for including any reliability-related constraints that
are requested to be included by another Transmission Operator, provided that (1) the request
references this specific requirement, and (2) the requesting Transmission Operator includes
those constraints in its TFC or TTC determination.
1.3.1 Each Transmission Operator that uses the Flowgate Methodology shall include in its
methodology an impact test process for including requested constraints. If a generator to
Load transfer in a registered entity’s area or a transfer to a neighboring registered entity
impact the requested constraint by five percent or greater, the requested constraint shall
be included in the TFC determination, otherwise the requested constraint is not required
to be included.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

3

1.3.2 Each Transmission Operator that uses the Area Interchange or Rated System Path
Methodology shall describe the process it uses to account for requested constraints that
have a five percent or greater distribution factor for a transfer between areas in the TTC
determination; otherwise the requested constraint is not required to be included. When
testing transfers involving the requesting Transmission Operators area, the requested
constraint may be excluded.
1.3.3 A different method for determining whether requested constraints need to be included
in the TFC or TTC determination may be used if agreed to by the Transmission Operators.
M1. Each Transmission Operator that determines TFC or TTC shall provide its current methodology (or
methodologies) or other evidence (such as written documentation) to show that its methodology (or
methodologies) contains the following:
A description of the method used to account for the limits specified in part 1.1. Methods of
accounting for these limits may include, but are not limited to, one or more of the following:
o TFC or TTC being determined by one or more limits.
o Simulation being used to find the maximum TFC or TTC that remains within the limit.
o The application of a distribution factor in determining if a limit affects the TFC or TTC value.
o Monitoring a subset of limits and a statement that those limits are expected to produce the
most severe results.
o A statement that the monitoring of a select limit(s) results in the TFC or TTC not exceeding
another set of limits.
o A statement that one or more of those limits are not applicable to the TFC or TTC
determination.
A description of the method used to account for the elements specified in part 1.2, provided such
elements impact the determination of TFC or TTC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:
o A statement that the element is not accounted for since it does not affect the determination
of TFC or TTC.
o A description of how the element is used in the determination of TFC or TTC.
(1.3) A copy of the request and a description of the method used to perform the impact test
(1.3.1) or account for the requested constraints (1.3.2).
The Transmission Operator shall also be using their current method to determine TFC or TTC.
Evidence of this could be, but is not limited to, a demonstration that a selection of currently
active TFC or TTC values were calculated based on the current methodology.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

4

Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested4:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M1 for evidence to demonstrate compliance.
See notes to auditor section when the TOP does not determine TFC or TTC values.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R1
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Review the methodology (or methodologies or other evidence per M1) and determine whether it
addresses all the sub-requirements of Requirement R1.
Note to Auditor: With regard to “current” practices, the auditor may at their discretion ask for a live
demonstration during the audit of currently determined values, or may ask for written evidence that
demonstrates the values were calculated based on the current practice, or both.
4

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

5

Although a registered entity may meet the registration criteria to be registered as a Transmission Operator,
there are instances where that Transmission Operator does not determine TFC or TTC values. In these
instances, as the registered entity does not determine these values, it would therefore not be required to
fulfill the requirements.
An auditor will first come to an understanding of how the entity operates and whether they determine TFC or
TTC. In the event that it is clear to the auditor that the entity does not determine TFC or TTC, this will be
sufficient evidence for the auditor that the appropriate requirements are not applicable to that entity. If
questions remain after this verification, the auditor could look to neighboring entities for confirmation.

Auditor Notes:

R2 Supporting Evidence and Documentation
R2.

Each Transmission Service Provider that determines Available Flowgate Capability (AFC) or Available
Transfer Capability (ATC) shall develop an Available Transfer Capability Implementation Document
(ATCID) that describes the methodology (or methodologies) it uses to determine AFC or ATC values.
The methodology (or methodologies) shall reflect the Transmission Service Provider’s current
practices for determining AFC or ATC values. Each methodology shall describe the method used to
account for the following elements that impact the determination of AFC or ATC:
2.1. Each methodology shall describe the method used to account for the following elements that
impact the determination of AFC or ATC:
2.1.1.

The simulation of transfers performed through the adjustment of generation, Load, or
both;

2.1.2.

Transmission topology, including, but not limited to, additions and retirements;

2.1.3.

Expected transmission uses;

2.1.4.

Planned outages;

2.1.5.

Parallel path (loop flow) adjustments;

2.1.6.

Load forecast; and

2.1.7.

Generator dispatch, including, but not limited to, additions and retirements.

2.2. Each Transmission Service Provider that uses the Flowgate Methodology shall, for reliability
constraints identified in part 1.3, use the AFC determined by the Transmission Service Provider
for that constraint.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

6

M2. Each Transmission Service Provider that determines AFC or ATC shall provide its current ATCID or
other evidence (such as written documentation) to show that its ATCID contains the following:
A description of the method used to account for the elements specified in part 2.1, provided such
elements impact the determination of AFC or ATC. Methods of accounting for these elements
may include, but are not limited to, one or more of the following:
o A description of how the element is used in the determination of AFC or ATC.
o A statement that the element is not accounted for since it does not affect the determination
of AFC or ATC.
o A statement that the element is accounted for in the determination of TFC or TTC by the
Transmission Operator, and does not otherwise affect the determination of AFC or ATC.
Each Transmission Service Provider that uses the Flowgate Methodology shall provide a
description of the method in which AFC provided by another Transmission Service Provider was
used for the reliability constraints identified in part 1.3.
The Transmission Service Provider shall also be using their current method to determine AFC or
ATC. Evidence of this could be, but is not limited to, a demonstration that a selection of currently
active AFC or ATC values were calculated based on the current methodology.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested5:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M2 for evidence to demonstrate compliance.
See notes to auditor section when the TSP does not determine AFC or ATC values.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
5

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

7

Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R2
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Review the methodology (or methodologies or other evidence per M2) and determine whether it
addresses all the sub-requirements of Requirement R2.
Note to Auditor: With regard to “current” practices, the auditor may at their discretion ask for a live
demonstration during the audit of currently determined values, or may ask for written evidence that
demonstrates the values were calculated based on the current practice, or both.
Although a registered entity may meet the registration criteria to be registered as a Transmission Service
Provider, there are instances where that Transmission Service Provider does not determine AFC or ATC. In
these instances, as the registered entity does not determine these values, it would therefore not be required
to fulfill the requirements.
An auditor will first come to an understanding of how the entity operates and whether they determine AFC or
ATC. In the event that it is clear to the auditor that the entity does not determine AFC or ATC, this will be
sufficient evidence for the auditor that the appropriate requirements are not applicable to that entity. If
questions remain after this verification, the auditor could look to neighboring entities for confirmation.

Auditor Notes:

R3 Supporting Evidence and Documentation
R3.

Each Transmission Service Provider that determines Capacity Benefit Margin (CBM) values shall
develop a Capacity Benefit Margin Implementation Document (CBMID) that describes its method for
establishing CBM. The method described in the CBMID shall reflect the Transmission Service
Provider’s current practices for determining CBM values.

DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

8

M3. Each Transmission Service Provider that determines CBM shall provide evidence, including, but not
limited to, its current CBMID, current CBM values, or other evidence (such as written documentation,
study reports, or supporting information) to demonstrate that it established CBM values consistent
with its methodology described in the CBMID. If a Transmission Service Provider does not maintain
CBM, examples of evidence include, but are not limited to, an affidavit, statement, or other
documentation that states the Transmission Service Provider does not maintain CBM.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested6:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M3 for evidence to demonstrate compliance.
See notes to auditor section when the TSP does not determine CBM values.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

6

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

9

Compliance Assessment Approach Specific to MOD-001-2, R3
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Review evidence and determine whether it describes the entity’s current method for establishing CBM.
Note to Auditor: In cases where a registered entity asserts it does not determine CBM, this requirement is not
applicable. An auditor could use his or her knowledge of the entity and the BES in its area, obtained through
general knowledge or research conducted prior to the audit, to assess the reasonableness of this claim. An
auditor could also obtain an attestation that the registered entity does not determine CBM and may further
look into the registered entity’s ATC equations for previously determined values to see that CBM was not
determined.
This approach to compliance assessment is supported in FERC Order 729 at P 298, FERC stated, “though MOD004-1 [CBM] is not as explicit with regard to its applicability, we believe that its applicability is implicitly
reserved to those entities that maintain capacity benefit margin. Thus, it does not appear that Entergy, or any
other entity, would be in violation of MOD-004-1 [CBM] or MOD-008-1 [TRM] if it does not maintain
transmission reliability margin or capacity benefit margin.”

Auditor Notes:

R4 Supporting Evidence and Documentation
R4. Each Transmission Operator that determines Transmission Reliability Margin (TRM) values shall
develop a Transmission Reliability Margin Implementation Document (TRMID) that describes its
method for establishing TRM. The method described in the TRMID shall reflect the Transmission
Operator’s current practices for determining TRM values.
M4. Each Transmission Operator that determines TRM shall provide evidence including, but not limited
to, its current TRMID, current TRM values, or other evidence (such as written documentation,
study reports, or supporting information) to demonstrate that it established TRM values
consistent with its methodology described in the TRMID. If a Transmission Operator does not
maintain TRM, examples of evidence include, but are not limited to, an affidavit, statement, or
other documentation that states the Transmission Operator does not maintain TRM.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.
DRAFT NERC Reliability Standard Audit Worksheet
Audit ID: Audit ID if available; or NCRnnnnn-YYYYMMDD
RSAW Version: RSAW_MOD-001-2_2013_v1 Revision Date: October 31, 2013

10

Evidence Requested7:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M4 for evidence to demonstrate compliance.
See notes to auditor section when the TOP does not determine TRM values.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R4
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Review evidence and determine whether it describes the entity’s current method for establishing TRM.
Note to Auditor: In cases where a registered entity asserts it does not determine TRM, this requirement is not
applicable. An auditor could use his or her knowledge of the entity and the BES in its area, obtained through
general knowledge or research conducted prior to the audit, to assess the reasonableness of this claim. An
auditor could also obtain an attestation that the registered entity does not determine TRM, and may further
investigate the registered entity’s ATC equations for previously determined values to see that TRM was not
determined. If the Transmission Operator is not a Transmission Service Provider, then the Transmission
Service Provider that uses the Transmission Operator’s TFC or TTC Values (if there is one) can be contacted (at
the auditor’s discretion) to confirm they do not use a TRM provided by the Transmission Operator.
7

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
DRAFT NERC Reliability Standard Audit Worksheet
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11

This approach to compliance assessment is supported in FERC Order 729 at P 298, FERC stated, “though MOD004-1 [CBM] is not as explicit with regard to its applicability, we believe that its applicability is implicitly
reserved to those entities that maintain capacity benefit margin. Thus, it does not appear that Entergy, or any
other entity, would be in violation of MOD-004-1 [CBM] or MOD-008-1 [TRM] if it does not maintain
transmission reliability margin or capacity benefit margin.”
Auditor Notes:

R5 Supporting Evidence and Documentation
R5. Within 45 calendar days of receiving a written request that references this specific requirement
from a Planning Coordinator, Reliability Coordinator, Transmission Operator, Transmission
Planner, Transmission Service Provider, or any other registered entity that demonstrates a
reliability need, each Transmission Operator or Transmission Service Provider shall provide:
5.1.

A written response to any request for clarification of its TFC or TTC methodology, ATCID,
CBMID, or TRMID. If the request for clarification is contrary to the Transmission Operator’s
or Transmission Service Provider’s confidentiality, regulatory, or security requirements
then a written response shall be provided explaining the clarifications not provided, on
what basis and whether there are any options for resolving any of the confidentiality,
regulatory, or security concerns.

5.2.

If not publicly posted on OASIS or its company website, the Transmission Operator’s
effective:
5.2.1 TRMID; and
5.2.2 TFC or TTC methodology.

5.3.

If not publicly posted on OASIS or its company website, the Transmission Service Provider’s
effective:
5.3.1 ATCID; and
5.3.2 CBMID.

M5. Examples of evidence include, but are not limited to:
Dated records of the request and the Transmission Operator’s or Transmission Service
Provider’s response to the request;
A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests; or

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12

A statement by the Transmission Operator or Transmission Service Provider that they do not
determine one or more of these values: AFC, ATC, CBM, TFC, TTC or TRM.
Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested8:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M5 for evidence to demonstrate compliance.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R5
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Through either discussions with the entity under audit or other Planning Coordinators, Reliability
8

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.
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13

Coordinators, Transmission Operators, Transmission Planners, Transmission Service Providers, or any
combination thereof, determine if a request was made in accordance with parts 5.1 through 5.3. If such a
request was made, then determine that the entity under audit responded in accordance with parts 5.1
through 5.3 within 45 calendar days from receipt of the request.
Note to Auditor: In general, evidence obtained from independent third parties is stronger than assertions
from the entity under audit. However, based upon the auditor’s perception of the risk of this requirement to
the BES and the entity’s management practices (or internal controls) a simple assertion may provide sufficient
evidence of compliance in many cases.
The aforementioned 45 day time period begins on the day when the written request was received by the
entity. Dated emails would constitute one example of appropriate evidence of receipt and response under this
requirement.
Auditor Notes:

R6 Supporting Evidence and Documentation
R6. Each Transmission Operator or Transmission Service Provider that receives a written request from
another Transmission Operator or Transmission Service Provider for data related to AFC, ATC, TFC,
or TTC determinations that (1) references this specific requirement, and (2) specifies that the
requested data is for use in the requesting party’s AFC, ATC, TFC, or TTC determination shall take
one of the actions below. [Violation Risk Factor: Lower] [Time Horizon: Operations Planning]
6.1. In responding to a written request for data on an ongoing basis, the Transmission Service
Provider or Transmission Operator shall make available its data on an ongoing basis no later
than 45 days from receipt of the written request. Unless otherwise agreed upon, the
Transmission Operator or Transmission Service Provider is not required to:
6.1.1 Alter the format in which it maintains or uses the data; or
6.1.2 Make available the requested data on a more frequent basis than it produces the
data and in no event shall it be required to provide the data more frequently than
once an hour.
6.2 In responding to all other data requests, each Transmission Operator or Transmission Service
Provider shall make available the requested data within 45 days of receipt of the written
request. Unless otherwise agreed upon, the Transmission Operator or Transmission Service
Provider is not required to alter the format in which it maintains or uses the data.
6.3 If making available any requested data under parts 6.1 or 6.2 of this requirement is contrary
to the Transmission Operator’s or Transmission Service Provider’s confidentiality, regulatory,
or security requirements, the Transmission Operator or Transmission Service Provider shall
not be required to make available that data; provided that, within 45 days of the written
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14

request, it responds to the requesting registered entity specifying the data that is not being
provided, on what basis and whether there are any options for resolving any of the
confidentiality, regulatory or security concerns.
M6. Examples of evidence for a data request that involves providing data at regular intervals on an
ongoing basis (6.1), include, but are not limited to:
Dated records of a registered entity’s request, and examples of the response being met;
Dated records of a registered entity’s request, a statement from the requestor that the
request was met (demonstration that the response was met is not required if the requestor
confirms it is being provided); or
A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.
Examples of evidence for all other data requests (6.2) include, but are not limited to:
Dated records of a registered entity’s request, and the response to the request;
Dated records of a registered entity’s request, a statement from the requestor that the
request was met; or
A statement by the Transmission Operator or Transmission Service Provider that they have
received no requests under this requirement.
An example of evidence of a response by the Transmission Operator or Transmission Service
Provider that providing the data would be contrary to the registered entity’s confidentiality,
regulatory, or security requirements (6.3) includes a response to the requestor specifying the data
that is not being provided, on what basis and whether there are any options for resolving any of
the confidentiality, regulatory, or security concerns.

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15

Registered Entity Response to General Compliance with this Requirement (Required):
Describe, in narrative form, how you meet compliance with this Requirement. Provide a brief explanation, in your own
words, of how you meet compliance with this Requirement. References to supplied evidence, including links to the
appropriate page, are recommended.

Evidence Requested9:
Provide the following evidence, or other evidence to demonstrate compliance. If the provisioning of this
evidence is burdensome or otherwise unreasonable, contact your CEA to arrange for sampling or other means
of reduction of the quantity of evidence submitted.
See M6 for evidence to demonstrate compliance.

Registered Entity Evidence (Required):
The following information is recommended for all evidence submitted:
File Name, Document Title, Revision, Date, Page(s), Section(s), Section Title(s), Description
Also, evidence submitted should be highlighted and bookmarked, as appropriate, to identify the exact location
where evidence of compliance may be found.

Audit Team Evidence Reviewed (This section to be completed by the Compliance Enforcement Authority):

Compliance Assessment Approach Specific to MOD-001-2, R6
This section to be completed by the Compliance Enforcement Authority
The RSAW Developer will complete this section with a set of detailed steps for the audit process. See the
RSAW Developer’s Guide for more information.
Through either discussions with the entity under audit or other Transmission Service Providers,
Transmission Operators, or any combination thereof, determine if a request was made in accordance with
Requirement R6. If such a request was made, then determine that the entity under audit responded in
accordance with parts 6.1 through 6.3 within 45 calendar days from receipt of the request.
Note to Auditor: In general, evidence obtained from independent third parties is stronger than assertions
from the entity under audit. However, based upon the auditor’s perception of the risk of this requirement to
the BES and the entity’s management practices (or internal controls) a simple assertion may provide sufficient
evidence of compliance in many cases.
The aforementioned 45 day time period begins on the day when the written request was received by the
entity. Dated emails would constitute one example of appropriate evidence of receipt and response under this
requirement.
9

Items in the Evidence Requested section are suggested evidence that may, but will not necessarily, demonstrate compliance. These
items are not mandatory and other forms and types of evidence may be submitted at the entity’s discretion.

DRAFT NERC Reliability Standard Audit Worksheet
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Auditor Notes:

Revision History
Version
1

Date
10/31/2013

Reviewers
NERC Compliance,
Standards

Revision Description
New Document

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17

Project 2012-05 - ATC Revisions (MOD A)
Consideration of Directives (November 12, 2013)
Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10204 – Order No. 729 at P 129
129. If the Commission determines upon its own review of the data,
or upon review of a complaint, that it should investigate the
implementation of the available transfer capability methodologies,
the Commission will need access to historical data. Accordingly,
pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, the Commission directs the ERO to modify the Reliability
Standards so as to increase the document retention requirements to a
term of five years, in order to be consistent with the enforcement
provisions established in Order No. 670.

1

(2000)).

Consideration of Directive
Consistent with FERC’s directive, proposed MOD-001-2 requires
applicable registered entities to retain the implementation and
methodology documents required under Requirements R1-R4 for
five years. For the components of the calculations and the results of
such calculations for all values contained in the implementation
and methodology documents, the proposed standard provides a
graduated time frame for the calculations of hourly, daily, and
monthly values. Evidence of hourly values must be retained for 14
days, daily values for 30 days and monthly values for 60 days. The
standard drafting team (“SDT”) concludes there is little to no
benefit of requiring entities to retain such detailed supporting data
of the calculations for longer periods. The SDT notes that to comply
with Commission requirements under Order No. 670,1 however,
entities may be required to retain such supporting data for longer
periods.

Prohibition of Energy Market Manipulation, Order No. 670, 71 FR 4244 (Jan. 26, 2006), FERC Stats. & Regs. ¶ 31,202, at PP 62- 63 (2006) (citing 28 U.S.C. § 2462

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10206 – Order No. 729 at P 151
151. Nevertheless, the Commission believes that the lists of required
recipients of the implementation documents may be overly
prescriptive and could exclude some registered entities with a
reliability need to review such information. Accordingly, pursuant to
section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop a modification to the
Reliability Standards pursuant to the ERO’s Reliability Standards
development process to require disclosure of the various
implementation documents to any registered entity who
demonstrates to the ERO a reliability need for such information.

VRF and VSL Justifications

Consideration of Directive
Consistent with the Commission’s directive, Requirement R5 of the
proposed standard requires that the implementation documents be
made available to any registered entity that demonstrates a
reliability need for such information, subject to confidentiality,
regulatory, and security requirements.

2

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10207 – Order No. 729 at P 160
160. In Order No. 890, the Commission also expressed concern
regarding the treatment of reservations with the same point of receipt
(generator), but multiple points of delivery (Load), in setting aside
existing transmission capacity. The Commission found that such
reservations should not be modeled in the existing transmission
commitments calculation simultaneously if their combined reserved
transmission capacity exceeds the generator’s nameplate capacity at
the point of receipt. The Commission required the development of
Reliability Standards that lay out clear instructions on how these
reservations should be accounted for by the transmission service
provider. The proposed Reliability Standards achieve this by requiring
transmission service providers to identify in their implementation
documents how they have implemented MOD-028-1, MOD-029-1, or
MOD-030-2, including the calculation of existing transmission
commitments. Thus we will not direct the ERO to develop a
modification to address over-generation, as suggested by Entegra.
Nonetheless, in developing the modifications to the MOD Reliability
Standards directed in this Final Rule, the ERO should consider
generator nameplate ratings and transmission line ratings including
the comments raised by Entegra and ISO/RTO Council.

2

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed reliability standard. First, in a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.2 Additionally, the SDT concludes that the comments
regarding generator nameplate ratings and transmission line
ratings do not relate to the reliability issues associated with
Available Flowgate Capability (AFC) and Available Transfer
Capability (ATC) calculations. The SDT notes that the comments
relate to the determination of existing transmission commitments
(ETC), which is a component of ATC or AFC that would be disclosed
in an entity’s Available Transfer Capability Implementation
Document (ATCID) under Requirement R2 of the proposed
standard. Specifying the manner in which ETC is determined, which
would include generator nameplate ratings and transmission line
ratings, where appropriate, is not necessary for reliability purposes.
NERC is working with the North American Energy Standards Board
(NAESB) to transfer those elements from the MOD A standards that
relate to commercial or business practices and are not included in
proposed MOD-001-2 into NAESB’s business practice standards.
When considering whether to incorporate those elements into its
business practice standards, NAESB could consider whether it is
appropriate to address this directive.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

3

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10208 – Order No. 729 at P 162
162. In Order No. 890, the Commission directed public utilities,
working through NERC, to modify MOD-010 through MOD-025 to
incorporate a periodic review and modification of various data
models. The Commission found that updating and benchmarking was
essential to accurately simulate the performance of the transmission
grid and to calculate comparable available transfer capability values.
On rehearing, the Commission clarified that the models used by the
transmission provider to calculate available transfer capability, and
not actual available transfer capability values, must be benchmarked.
Updating and benchmarking of models to actual events will ensure
greater accuracy, which will benefit information provided to and used
by adjacent transmission service providers who rely upon such
information to plan their systems. Accordingly, pursuant to section
215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop benchmarking and updating
requirements to measure modeled available transfer and flowgate
capabilities against actual values. Such requirements should specify
the frequency for benchmarking and updating the available transfer
and flowgate capability values and should require transmission service
providers to update their models after any incident that substantially
alters system conditions, such as generation outages.

VRF and VSL Justifications

Consideration of Directive
The SDT concludes that the proposed standard is responsive to the
Commission’s concern regarding the accuracy of ATC/AFC values as
system conditions change. Requirements R1 (part 1.2) and R2 (part
2.1) of the proposed standard require that a Transmission
Operator’s (TOP’s) and a Transmission Service Providers (TSP’s)
models for determining Total Flowgate Capability (TFC) or Total
Transfer Capability (TTC) or AFC/ATC, respectively, account for
system topology, including additions and retirements as well as
expected system usage, planned outages, Load forecast and
expected generation dispatch when such elements impact the
determination of TFC, TTC, AFC or ATC. By describing how its
methodology accounts for these elements, adjacent systems will be
able to effectively model their own transfer or flowgate capabilities.
The SDT concludes, however, that because each part of the country
has a different sensitivity to these elements and the frequency with
which they change, there is no additional reliability benefit in
mandating the frequency with which a TOP or TSP must benchmark
or update its models. Under Requirement R6 of the proposed
standard, registered entities are required to share their data with
others, which also increases the amount of up to date information
available for the determination of AFC/ATC values. Additionally,
under Requirements R5 of the proposed standard, a TSP or a TOP
could be asked to clarify its benchmarking or updating practices, if
not already set forth in its documented methodology, and share
data underling those practices. As such, the proposed reliability
addresses the Commission’s directive toward increasing accuracy by
improving transparency.

4

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10209 – Order No. 729 at P 173
173. The Commission therefore directs the ERO, pursuant to section
215(d)(5) of the FPA and section 39.5(f) of our regulations, to develop
a modification to MOD-028-1 and MOD-029-1 to specify that base
generation schedules used in the calculation of available transfer
capability will reflect the modeling of all designated network
resources and other resources that are committed to or have the legal
obligation to run, as they are expected to run, and to address the
effect on available transfer capability of designating and
undesignating a network resource.

NERC S-Ref 10211 – Order No. 729 at P 179
179. We agree that, in order to be useful, hourly, daily and monthly
available transfer capability and available flowgate capability values
must be calculated and posted in advance of the relevant time period.
Requirement R8 of MOD-001-1 and Requirement R10 of MOD-030-2
require that such posting will occur far enough in advance to meet this
need. With respect to Entegra’s request regarding more frequent
updates for constrained facilities, we direct the ERO to consider this
suggestion through its Reliability Standards development process.

3

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. The SDT concludes that this directive
does not relate to the reliability issues associated with ATC or AFC
determinations. Specifically, the directive relates to the inputs for
calculating ETC, which is not relevant to reliability. The SDT
concludes that there is no reliability purpose served by mandating
how generation and network resources should be treated so long
as it is transparent. The SDT notes that under Requirement R2 of
the proposed standard, a TSP should describe its practices related
to the treatment of base generation schedules and the effect of
designating and undesignating a network resource. Under
Requirement R5 of the proposed reliability standard, the TSP will be
required to respond to requests for clarification of its practices on
this issue. The SDT notes that NAESB could consider whether to
address this directive from a commercial perspective.
The SDT determines that it is not necessary to address this directive
in the proposed standard. In a recent Notice of Proposed
Rulemaking, the Commission proposed to withdraw this directive.3
Additionally, the SDT concludes that the frequency of updates for
constrained facilities is not relevant to reliability but relates to
commercial access to the constrained paths. The SDT notes,
however, that an entity’s ATCID should address this issue. NAESB
could consider whether to address this directive from a commercial
perspective.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

5

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10212 – Order No. 729 at P 179
179. Further, we agree with Cottonwood regarding unscheduled or
unanticipated events. Therefore, pursuant to section 215(d)(5) of the
FPA and section 39.5(f) of our regulations, we direct the ERO to
develop modifications to MOD-001-1 and MOD-030-2 to clarify that
material changes in system conditions will trigger an update whenever
practical. Finally, we clarify that these Reliability Standards shall not
be used as a “safe harbor” to avoid other, more stringent reporting or
update requirements.
NERC S-Ref 10214 – Order No. 729 at P 184
184. As proposed, MOD-001-1 does not restrict a transmission service
provider from double-counting data inputs or assumptions in the
calculation of available transfer or flowgate capability. To the extent
possible, available transfer or flowgate capability values should reflect
actual system conditions. The double-counting of various data inputs
and assumptions could cause an understatement of available transfer
or flowgate capability values and, thus, poses a risk to the reliability of
the Bulk-Power System. We note that, in the Commission’s order
accepting the associated NAESB business standards, issued
concurrently with this Final Rule in Docket No. RM05-5-013, the
Commission directs EPSA to address its concerns regarding the
modeling of condition firm service through the NERC Reliability
Standards development process. We reaffirm here that modeling of
available transfer capability should consider the effects of conditional
firm service, including the potential for double-counting. Accordingly,
pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our
regulations, the Commission directs the ERO to develop modifications
to MOD-001-1 pursuant to the ERO’s Reliability Standards
development process to prevent the double-counting of data inputs
and assumptions. In developing these modifications, the ERO should
consider the effects of conditional firm service.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. The proposed standard is limited to
addressing reliability issues associated with AFC/ATC
determinations. The need to update due to material changes in
system condition is not needed for reliability but serves the
purpose of providing the best information to the market. As such, it
may be appropriate for NAESB to address this issue in its business
practice standards. The SDT notes, however, that an entity’s ATCID
could address this issue.
The SDT concludes that the proposed standard is responsive to the
Commission’s concern. By requiring the documentation and
disclosure of the methodologies for determining TTC/TFC, AFC/ATC,
Capacity Benefit Margin (CBM) and Transmission Reliability Margin
(TRM), registered entities will understand how a neighboring entity
calculates these values and, in turn, reduces the reliability risks
associated with potentially double-counting any data inputs and
assumptions. NAESB may also consider whether the possibility of
double-counting needs to be addressed in greater detail in its
business practice standards.

6

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10215 – Order No. 729 at P 192
192. In its filing letter, NERC states that it requires applicable entities
to calculate available transfer capability or available flowgate
capability on a consistent schedule and for specific time frames. In
keeping with the Commission’s goals of consistency and transparency
in the calculation of available transfer capability or available flowgate
capability, the Commission finds that transmission service providers
should use consistent modeling practices over different time frames. If
a transmission service provider uses inconsistent modeling practices
over different time frames that should be made explicit in its
implementation document along with a justification for the
inconsistent practices. Accordingly, pursuant to section 215(d)(5) of
the FPA and section 39.5(f) of our regulations, the Commission directs
the ERO to develop a modification to the Reliability Standard pursuant
to its Reliability Standards development process requiring
transmission service providers to include in their implementation
documents any inconsistent modeling practices along with a
justification for such inconsistencies.

VRF and VSL Justifications

Consideration of Directive
The SDT concludes that the proposed standard is responsive to the
Commission’s concern. By requiring that TSPs and TOPs document
their methodologies for determining TTC/TFC, AFC/ATC, CBM and
TRM to reflect their current practices, the TSP/TOP must provide
information regarding their modeling practices, including whether
those modeling practices are used consistently. Additionally,
Requirement R5 allows registered entities to request that the
TSP/TOP clarify its methodology, which includes requests about the
TSP’s/TOP’s modeling practices. Should NAESB see a need for
additional detail on modeling practices for purposes of ensuring a
non-discriminatory market, it may further consider this directive.

7

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10216 – Order No. 729 at P 200
200. With regard to Midwest ISO’s concern, while the terms
“assumptions” and “no more limiting” as used in Requirements R6
and R7 could benefit from further granularity, we find these
Requirements to be sufficiently clear for purposes of compliance.
Likewise, with regard to Entegra’s concern, we agree that
transmission service providers should use data and assumptions for
their available transfer capability or available flowgate capability and
total transfer capability or total flowgate capability calculations that
are consistent with those used in the planning of operations and
system expansion. Under Requirements R6 and R7, transmission
service providers and transmission operators must not overstate
assumptions that are used in planning of operations. We believe these
requirements are sufficiently clear as written. Nonetheless, we
encourage the ERO to consider Midwest ISO’s and Entegra’s
comments when developing other modifications to the MOD
Reliability Standards pursuant to the ERO’s Reliability Standards
development procedure.

4

Consideration of Directive
The SDT determines that it is not necessary to address this directive
in the proposed standard. In a recent Notice of Proposed
Rulemaking, the Commission proposed to withdraw this directive.4
There is no additional reliability benefit to specifically including a
requirement that the TOP explain how it uses consistent or less
limiting assumptions than their operations planning. This issue may
be considered further by NAESB if it is important for commercial
purposes.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

8

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10217 – Order No. 729 at P 220
220. We agree with NERC that a transmission service provider should
consider any information provided in establishing an appropriate level
of capacity benefit margin. Similarly, we agree with the Georgia
Companies that all relevant information should be considered in
establishing an appropriate level of capacity benefit margin, including
information provided by customers. However, in determining the
appropriate generation capacity import requirement as part of the
sum of capacity benefit margin to be requested from the transmission
service provider, it would not be appropriate for a load-serving entity
or resource planner to rely exclusively on a reserve margin or
adequacy requirement established by an entity that is not subject to
this Standard. Thus, we hereby adopt the NOPR proposal to direct the
ERO to develop a modification to Requirements R3.1 and R.4.1 of
MOD-004-1 to require load-serving entities and resource planners to
determine generation capability import requirements by reference to
one or more relevant studies (loss of load expectation, loss of load
probability or deterministic risk analysis) and applicable reserve
margin or resource adequacy requirements, as relevant. Such a
modification should ensure that a transmission service provider has
adequate information to establish the appropriate level of capacity
benefit margin.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. Under the proposed
standard, the method of calculating CBM is determined by the TSP
and must be described in the TSP’s CBMID. The SDT concludes that
no reliability benefit is provided by placing a requirement on Load
Serving Entities (LSEs) and Resource Planners (RPs) to determine
generation capability import requirements by reference to one or
more relevant studies and applicable reserve margin or resource
adequacy requirements. This issue may be considered further by
NAESB if it is important for commercial purposes.

9

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10218 – Order No. 729 at P 222
222. We agree with the Midwest ISO that ISOs, RTOs, and other
entities with a wide view of system reliability needs should be able to
provide input into determining the total amount of capacity benefit
margin required to preserve the reliability of the system. However,
Requirements R1.3 and R7 already make clear that determinations of
need for generation capability import requirement made by a load
serving entity or resource planner are not final. Further, the third
bullet of Requirements R5 and R6 explicitly lists reserve margin or
resource adequacy requirements established by RTOs and ISOs among
the factors to be considered in establishing capacity benefit margin
values for available transfer capability paths or flowgates used in
available transfer capability or available flowgate capability
calculations. In fact, it is for this reason that we uphold the NOPR
proposal. Therefore, pursuant to section 215(d)(5) of the FPA and
section 39.5(f) of our regulations, the Commission directs the ERO to
modify MOD-004-1 to clarify the term “manage” in Requirement R1.3.
This modification should ensure that the Reliability Standard clarify
how the transmission service provider will manage situations where
the requested use of capacity benefit margin exceeds the capacity
benefit margin available.

VRF and VSL Justifications

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. Under the proposed
reliability standard, the method of calculating CBM is determined
by the TSP and must be described in the TSP’s CBMID. The Capacity
Benefit Margin Implementation Document (CBMID) should describe
the manner in which the TSP will manage situations where the
requested use of CBM exceeds the CBM available. The SDT
concludes that no reliability benefit is provided specifically
requiring such a description. This issue may be considered further
by NAESB if it is important for commercial purposes.

10

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10219 – Order No. 729 at P 231
231. The Commission understands sub-requirement R2.2 of MOD-0281 to mean that, when calculating total transfer capability for available
transfer capability paths, a transmission operator shall use a
transmission model that includes relevant data from reliability
coordination areas that are not adjacent. While we believe that the
provision is reasonably clear, the Commission agrees that the term
“and beyond” could be better explained. Accordingly, pursuant to
section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the
Commission directs the ERO to develop a modification subrequirement R2.2 pursuant to its Reliability Standards development
process to clarify the phrase “adjacent and beyond Reliability
Coordination areas.”
NERC S-Ref 10220 - Order No. 729 at P 234
234. The Commission believes that, as written, the time frames
established in Requirement R5 are just and reasonable because they
balance the need to reliably operate the grid with the burden on
transmission operators to recalculate total transfer capability even
when total transfer capability does not often change. Nevertheless,
the Commission agrees that a graduated time frame for reposting
could be reasonable in some situations. Accordingly, the ERO should
consider this suggestion when making future modifications to the
Reliability Standards.

Consideration of Directive
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.5 Additionally, the proposed standard does not use the
phrase “adjacent and beyond Reliability Coordination areas.”

The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.6 The SDT considered this issue and concludes that there
is no reliability benefit in requiring specific time frames for an Area
Interchange Methodology user to update their TTC based on an
outage. Under the proposed reliability standard, the time frame
within which a value is recalculated and reposted based on an
outage would be addressed by the TOP in its methodology. This
issue may be considered further by NAESB if it is important for
commercial purposes.

5

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

6

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

11

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10221 – Order No. 729 at P 237
237. The Commission agrees that any distribution factor to be used
should be clearly stated in the implementation document, and that to
facilitate consistent and understandable results the distribution
factors used in determining total transfer capability should be applied
consistently. Accordingly, pursuant to section 215(d)(5) of the FPA
and section 39.5(f) of our regulations, the Commission directs the ERO
to develop a modification to MOD-028-1 pursuant to its Reliability
Standards development process to address these two concerns.

NERC S-Ref 10222 – Order No. 729 at P 246
246. Puget Sound’s request is reasonable, and insofar as calculating
non-firm available transfer capability using counterschedules as
opposed to counterflows achieves substantially equivalent results,
using them will not be considered a violation. However, we do not
have enough information to determine that the terms are generally
interchangeable in all circumstances. The ERO should consider Puget
Sound’s concerns on this issue when making future modifications to
the Reliability Standards.

7

Consideration of Directive
The SDT concludes that the proposed reliability standard is
responsive to the Commission’s concern. First, the proposed
reliability standard requires disclosure of the TOP’s method of
addressing TTC/TFC and the TSP’s method of determining ATC/AFC.
These methods will describe the manner in which TOPs and TSPs
use distribution factors. The description must reflect current
practices. The proposed standard also allows neighboring TOPs to
request that a TOP consider a transmission constraint in its TTC/TFC
determination. Users of the Area Interchange or Rated System Path
Methodology must describe the process they use to account for
requested constraints that have a five percent or greater
distribution factor for a transfer between areas in the TTC
determination.
The SDT determines that it is not necessary to specifically address
this directive in the proposed standard. In a recent Notice of
Proposed Rulemaking, the Commission proposed to withdraw this
directive.7 Additionally, the SDT concludes that the issue raised by
Puget Sound is outside the scope of the reliability issues associated
with ATC/AFC determinations.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

12

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10223 – Order No. 729 at P 269
269. As noted above, the Commission approves the proposal to make
these Reliability Standards effective on the first day of the first
calendar quarter that is twelve months beyond the date that the
Reliability Standards are approved by all applicable regulatory
authorities. Although MOD-030-2 defines its effective date with
reference to the effective date of MOD-030-1, the Commission finds
that this direction is sufficiently clear in the context of the current
proceeding. To the extent necessary, we clarify MOD-030-2 shall
become effective on the first day of the first calendar quarter that is
twelve months beyond the date that the Reliability Standards are
approved by all applicable regulatory authorities. The Commission
also directs the ERO to make explicit such detail in any future version
of this or any other Reliability Standard.
NERC S-Ref 10226 – Order No. 729 at P 304
304. The Commission believes that the definition of Postback is not
fully determinative. NERC should be able to define this term without
reference to the Business Practices, another defined term.
Accordingly, the Commission adopts its NOPR proposal and directs the
ERO to develop a modification to the definition of Postback to
eliminate the reference to Business Practices. Although we are
sensitive to Puget Sound’s concern that the required Postback
component may increase the recordkeeping burden on some entities,
in other regions the component may be critical. We disagree that the
term’s existence assumes that once a reservation is confirmed on a
particular point of reservation or point of receipt combination the
impact of the confirmed reservation will always be present in the
available transfer capability calculation. However, we would consider
suggestions that would allow entities to comply with the
requirements as efficiently as possible, such as a regional difference
through the ERO’s standards development procedure.

8

Consideration of Directive
The SDT determines that this directive is no longer relevant.
Additionally, in a recent Notice of Proposed Rulemaking, the
Commission proposed to withdraw this directive.8

Because the term “Postback” is not used in the proposed standard,
it is not necessary to address this directive. The term “Postback” is
not used in any other standard. Any necessary revisions to NERC’s
Glossary of Terms to remove the term “Postback” will be addressed
in a subsequent project modifying the NERC Glossary.

Electric Reliability Organization Proposal to Retire Requirements in Reliability Standards, 143 FERC ¶ 61,251 at P 85, Attachment A (2013).

VRF and VSL Justifications

13

Project 2012-05 ATC Revisions (MOD A)
Directive
NERC S-Ref 10227 – Order No. 729 at P 305
305. The Commission also adopts its NOPR proposal to direct the ERO
to develop a modification to the definition of Business Practices that
would remove the reference to regional reliability organizations and
replace it with the term Regional Entity. We also direct the ERO to
develop a definition of the term Regional Entity to be included in the
NERC Glossary.
NERC S-Ref 10229 – Order No. 729 at P 306
306. We agree with SMUD and Salt River that the definition of “ATC
Path” should not limit a transmission provider’s flexibility to treat
multiple parallel interconnections between balancing authorities as a
single path, and that available transfer capability paths may comprise
multiple, parallel interconnections between Balancing Authorities
when such treatment is appropriate to maintain reliability. We also
agree that the definition should not reference the Commission’s
regulations. The Commission’s regulations are not applicable to all
registered entities and are subject to change. We therefore direct the
ERO to develop a modification to the definition of “ATC Path” that
does not reference the Commission’s regulations.

VRF and VSL Justifications

Consideration of Directive
Because the term “Business Practices” is not used in the proposed
standard, it is not necessary to address this directive. Any
necessary revisions to NERC’s Glossary of Terms related to the term
“Business Practices” will be part of any subsequent project
modifying the NERC Glossary

Because the term “ATC Path” is not used in the proposed standard,
it is not necessary to address this directive. The term “ATC Path” is
not used in any other standard. Any necessary revisions to NERC’s
Glossary of Terms to remove the term “ATC Path” will be part of
any subsequent project modifying the NERC Glossary.

14

Violation Risk Factor and Violation Severity Level Justifications
MOD-001-2 – Available Transmission System Capability

This document provides the Standard Drafting Team’s (SDT) justification for assignment of violation risk factors (VRFs) and violation severity
levels (VSLs) for each requirement in MOD-001-2 – Available Transmission System Capability. Each requirement is assigned a VRF and a VSL.
These elements support the determination of an initial value range for the Base Penalty Amount regarding violations of requirements in
FERC-approved Reliability Standards, as defined in the Electric Reliability Organizations (ERO) Sanction Guidelines. The SDT applied the
following NERC criteria and FERC Guidelines when proposing VRFs and VSLs for the requirements under this project.
NERC Criteria - Violation Risk Factors
High Risk Requirement

A requirement that, if violated, could directly cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of
failures, or could place the Bulk Electric System at an unacceptable risk of instability, separation, or cascading failures; or, a requirement in a
planning time frame that, if violated, could, under emergency, abnormal, or restorative conditions anticipated by the preparations, directly
cause or contribute to Bulk Electric System instability, separation, or a cascading sequence of failures, or could place the Bulk Electric
System at an unacceptable risk of instability, separation, or cascading failures, or could hinder restoration to a normal condition.
Medium Risk Requirement

A requirement that, if violated, could directly affect the electrical state or the capability of the Bulk Electric System, or the ability to
effectively monitor and control the Bulk Electric System. However, violation of a medium risk requirement is unlikely to lead to Bulk Electric
System instability, separation, or cascading failures; or, a requirement in a planning time frame that, if violated, could, under emergency,
abnormal, or restorative conditions anticipated by the preparations, directly and adversely affect the electrical state or capability of the Bulk
Electric System, or the ability to effectively monitor, control, or restore the Bulk Electric System. However, violation of a medium risk
requirement is unlikely, under emergency, abnormal, or restoration conditions anticipated by the preparations, to lead to Bulk Electric
System instability, separation, or cascading failures, nor to hinder restoration to a normal condition.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

Lower Risk Requirement

A requirement that is administrative in nature and a requirement that, if violated, would not be expected to adversely affect the electrical
state or capability of the Bulk Electric System, or the ability to effectively monitor and control the Bulk Electric System; or, a requirement
that is administrative in nature and a requirement in a planning time frame that, if violated, would not, under the emergency, abnormal, or
restorative conditions anticipated by the preparations, be expected to adversely affect the electrical state or capability of the Bulk Electric
System, or the ability to effectively monitor, control, or restore the Bulk Electric System.
FERC Violation Risk Factor Guidelines
Guideline (1) – Consistency with the Conclusions of the Final Blackout Report

The Commission seeks to ensure that Violation Risk Factors assigned to Requirements of Reliability Standards in these identified areas
appropriately reflect their historical critical impact on the reliability of the Bulk-Power System. In the VSL Order, FERC listed critical areas
(from the Final Blackout Report) where violations could severely affect the reliability of the Bulk-Power System:
• Emergency operations
• Vegetation management
• Operator personnel training
• Protection systems and their coordination
• Operating tools and backup facilities
• Reactive power and voltage control
• System modeling and data exchange
• Communication protocol and facilities
• Requirements to determine equipment ratings
• Synchronized data recorders
• Clearer criteria for operationally critical facilities

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

• Appropriate use of transmission loading relief.
Guideline (2) – Consistency within a Reliability Standard

The Commission expects a rational connection between the sub-Requirement Violation Risk Factor assignments and the main Requirement
Violation Risk Factor assignment.
Guideline (3) – Consistency among Reliability Standards

The Commission expects the assignment of Violation Risk Factors corresponding to Requirements that address similar reliability goals in
different Reliability Standards would be treated comparably.
Guideline (4) – Consistency with NERC’s Definition of the Violation Risk Factor Level

Guideline (4) was developed to evaluate whether the assignment of a particular Violation Risk Factor level conforms to NERC’s definition of
that risk level.
Guideline (5) –Treatment of Requirements that Co-mingle More Than One Obligation

Where a single Requirement co-mingles a higher risk reliability objective and a lesser risk reliability objective, the VRF assignment for such
Requirements must not be watered down to reflect the lower risk level associated with the less important objective of the Reliability
Standard.
NERC Criteria - Violation Severity Levels
Violation Severity Levels (VSLs) define the degree to which compliance with a requirement was not achieved. Each requirement must have
at least one VSL. While it is preferable to have four VSLs for each requirement, some requirements do not have multiple “degrees” of
noncompliant performance and may have only one, two, or three VSLs.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

Violation severity levels should be based on NERC’s overarching criteria shown in the table below:
Lower VSL
Moderate VSL
High VSL
The performance or product
The performance or product
The performance or product
measured almost meets the full measured meets the majority of measured does not meet the
intent of the requirement.
the intent of the requirement.
majority of the intent of the
requirement, but does meet
some of the intent.

Severe VSL
The performance or product
measured does not
substantively meet the intent of
the requirement.

FERC Order of Violation Severity Levels
FERC’s VSL guidelines are presented below, followed by an analysis of whether the VSLs proposed for each requirement in the standard
meet the FERC Guidelines for assessing VSLs:
Guideline 1 – Violation Severity Level Assignments Should Not Have the Unintended Consequence of Lowering the Current
Level of Compliance
Compare the VSLs to any prior levels of non-compliance and avoid significant changes that may encourage a lower level of compliance than
was required when levels of non-compliance were used.
Guideline 2 – Violation Severity Level Assignments Should Ensure Uniformity and Consistency in the Determination of
Penalties
A violation of a “binary” type requirement must be a “Severe” VSL.
Do not use ambiguous terms such as “minor” and “significant” to describe noncompliant performance.
Guideline 3 – Violation Severity Level Assignment Should Be Consistent with the Corresponding Requirement
VSLs should not expand on what is required in the requirement.
Guideline 4 – Violation Severity Level Assignment Should Be Based on a Single Violation, Not on a Cumulative Number of
Violations

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

. . . unless otherwise stated in the requirement, each instance of non-compliance with a requirement is a separate violation. Section 4 of the
Sanction Guidelines states that assessing penalties on a per violation per day basis is the “default” for penalty calculations.

VRF and VSL Justifications – MOD-001-2, Requirement R1
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The reliability objective is for a Transmission Operator (TOP) to have a written methodology for
determining Total Transfer Capability (TTC) or Total Flowgate Capability (TFC), which are the starting
points for determinations of Available Transfer Capability (ATC) and Available Flowgate Capability (AFC).
Although AFC and ATC values influence Real‐time conditions and have the ability to impact Real‐time
operations, these values do not directly control the reliable operation of the Bulk-Power System.
Accordingly, a violation of this requirement would not be expected to adversely affect the electrical state
or capability of the bulk electric system, or the ability to effectively monitor and control the bulk electric
system. A Lower VRF is thus appropriate.
Additionally, currently effective Reliability Standards MOD-001-1a, MOD-028-2, MOD-029-1a, and MOD030-2, which are being retired as part of this project, assign a Lower VRF to requirements addressing the
documentation of TTC/TFC methodologies. The proposed Lower VRF is thus consistent with the VRFs for
previous FERC approved requirements related to TTC/TFC determination.

FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion

VRF and VSL Justifications

Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
The Lower VRF is applicable to all parts of the requirement.
Guideline 3- Consistency among Reliability Standards

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R1
This requirement is similar to FERC approved MOD-028-2, Requirement R1 and MOD-029-1a, Requirement
R2, which deals with TTC and were assigned a VRF of Lower. MOD-028-2 and MOD-029-1a are replaced by
Requirement R1, and therefore the proposed Lower VRF is consistent with those in the previously
approved standards.

FERC VRF G4 Discussion

FERC VRF G5 Discussion

The VRF for Requirement R1 is also consistent with the Lower VRF assignment in FAC-013-2, which also
contains requirements for documenting transfer capability.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective, to ensure that a TOP documents its TTC or TFC
methodology and accounts for relevant operating limits and system conditions. Therefore, the
requirement has one VRF that is appropriate for its single obligation.
Proposed VSL

Lower

Moderate

Each Transmission Operator
that determines TFC or TTC has
not described its method for
accounting for one of the
limitations listed in part 1.1 in
its written methodology. (1.1)

Each Transmission Operator
that determines TFC or TTC has
not described its method for
accounting for two of the
limitations listed in part 1.1 in
its written methodology. (1.1)

High
Each Transmission Operator that
determines TFC or TTC has not
described its method for
accounting for any of the
limitations listed in part 1.1 in its
written methodology. (1.1)

Severe
Each Transmission Operator that
determines TFC or TTC did not
develop a written methodology for
describing its current practices for
determining TFC or TTC values.
OR

OR

VRF and VSL Justifications

OR

OR

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R1
Each Transmission Operator
that determines TFC or TTC has
not described its method for
accounting for one of the
element listed in part 1.2 in its
written methodology, provided
that element impacts its TFC or
TTC determination. (1.2)

Each Transmission Operator
that determines TFC or TTC has
not described its method for
accounting for two, three, or
four elements listed in part 1.2
in its written methodology,
provided those elements
impacts its TFC or TTC
determination. (1.2)

Each Transmission Operator that
determines TFC or TTC has not
described its method for
accounting for five, six, or seven
elements of listed in part 1.2 in its
written methodology, provided
those elements impacts its TFC or
TTC determination. (1.2)
OR
Each Transmission Operator that
determines TFC or TTC has not
described the process for including
any reliability-related constraints
that have been requested by
another Transmission Operator,
provided the constraints are also
used in the requesting
Transmission Operator’s TFC or
TTC calculation and the request
referenced part 1.3. (1.3)
OR

VRF and VSL Justifications

Each Transmission Operator that
determines TFC or TTC developed
a written methodology for
determining TFC or TTC but the
methodology did not reflect its
current practices for determining
TFC or TTC values.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R1
Each Transmission Operator that
determines TFC or TTC has not
used (i) an impact test process for
including requested constraints,
(ii) a process to account for
requested constraints that have a
five percent or greater distribution
factor for a transfer between areas
in the TTC determination, or (iii) a
mutually agreed upon method for
determining whether requested
constraints need to be included in
the TFC or TTC determination.
(1.3.1, 1.3.2, 1.3.3)
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure

Guideline 2a:
The proposed VSL is not binary.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R1
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2b:
The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in the
determination of similar penalties for similar violations.

FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSLs are worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications

VRF and VSL Justifications – MOD-001-2, Requirement R2
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The reliability objective is to ensure that a TSP has a written methodology for determining Available
Transfer Capability (ATC) or Available Flowgate Capability (AFC). Although AFC and ATC values influence
Real‐time conditions and have the ability to impact Real‐time operations, these values do not directly
control the reliable operation of the Bulk-Power System. A violation of this requirement would not be
expected to adversely affect the electrical state or capability of the bulk electric system, or the ability to
effectively monitor and control the bulk electric system. As such, a Lower VRF is appropriate.

FERC VRF G1 Discussion
FERC VRF G2 Discussion
FERC VRF G3 Discussion

Additionally, currently effective Reliability Standards MOD-001-1a, MOD-028-2, MOD-029-1a, and MOD030-2, which are being retired as part of this project, assign VRFs of Lower for requirements related to the
documentation of ATC/AFC methodologies. This proposed Lower VRF is thus consistent with previously
FERC approved requirements.
Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
The Lower VRF is applicable to all parts of the requirement.
Guideline 3- Consistency among Reliability Standards
This requirement is similar to FERC approved MOD-028-2 Requirement R1 and MOD-030-2 Requirement
R1, which deal with TSPs that determine ATC to develop an ATCID and were assigned a VRF of Lower.
MOD-028-2 and MOD-030-2 will be replaced by Requirement R2, and therefore the Lower VRF is
consistent with the previously approved standards.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R2

FERC VRF G4 Discussion

FERC VRF G5 Discussion

FAC-013-2 also contains similar requirements for documenting transfer capability and aligns with the
proposed Lower VRFs in MOD-001-2. There are no other standards addressing this issue.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective, which is that a TSP’s ATC or AFC methodology must be
documented for those registered entities that determine ATC or AFC values and the document is to reflect
current practices. Therefore, the requirement has one VRF that is appropriate for its single obligation.
Proposed VSL

Lower

Moderate

High

Each Transmission Service
Provider that determines AFC
or ATC has not described its
method for accounting for one
of the elements listed in part
2.1 in its written methodology,
provided that element impacts
its AFC or ATC determination.
(2.1)

Each Transmission Service
Provider that determines AFC
or ATC has not described its
method for accounting for two,
three, or four elements listed in
part 2.1 in its written
methodology, provided the
elements impact its AFC or ATC
determination. (2.1)

Each Transmission Service Provider
that determines AFC or ATC has
not described its method for
accounting for five, six, or seven
elements listed in part 2.1 in its
written methodology, provided the
elements impact its AFC or ATC
determination. (2.1)

VRF and VSL Justifications

Severe
Each Transmission Service
Provider that determines AFC or
ATC did not develop an ATCID
describing its AFC or ATC
methodology.
OR

Each Transmission Service
OR
Provider that determines AFC or
ATC did not reflect its current
Each Transmission Service Provider practices for determining AFC or
that uses the Flowgate
ATC values in its ATCID.
Methodology did not use the AFC

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R2
determined by the Transmission
Service Provider for reliabilityrelated constraints identified in
part 1.3. (2.2)

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R2
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is not binary.

VRF and VSL Justifications

Guideline 2b:
The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in the
determination of similar penalties for similar violations.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R2
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R3
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The reliability objective is to ensure that a TSP that determines Capacity Benefit Margin (CBM), a
component of ATC/AFC values, documents its methodology for developing its CBM values, which is an
important aspect of the TSP’s ability to communicate to TOPs how its AFC or ATC value was determined.

FERC VRF G1 Discussion
FERC VRF G2 Discussion

FERC VRF G3 Discussion

FERC VRF G4 Discussion

FERC VRF G5 Discussion

VRF and VSL Justifications

As noted above, because ATC/AFC do not directly control the reliable operation of the Bulk-Power System,
a VRF of Lower is appropriate. Furthermore, the proposed Lower VRF is consistent with the FERC approved
MOD-004-1, in which the VRF is Lower for TSPs that maintain CBM.
Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
Requirement R3 does not have any sub-parts or sub-requirements. The Lower VRF is applicable to the
entire requirement.
Guideline 3- Consistency among Reliability Standards
The proposed Lower VRF is consistent with Lower VRF in FERC approved MOD-004-1, which requires TSPs
that maintain CBM to prepare and keep current a CBMID. MOD-004-1 will be retired upon approval of
MOD-001-2. There are no other standards addressing this issue.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R3
The proposed requirement has a single objective, to ensure that a TSP documents its CBM methodology in
an implementation document and ensure the document reflects current practices. Therefore, the
requirement has one VRF for its single obligation.
Proposed VSL
Lower
None.

Moderate
None.

High
None.

Severe
Each Transmission Service
Provider that determines CBM
values did not develop a CBMID
describing its method for
determining CBM values.
OR
Each Transmission Service
Provider that determines CBM
values did not reflect its current
practices for determining CBM
values in its CBMID.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R3
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is binary, and therefore, a single severe VSL is necessary.

VRF and VSL Justifications

Guideline 2b:
The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in the
determination of similar penalties for similar violations.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R3
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R4
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The reliability objective is to ensure that TOPs that determine Transmission Reliability Margin (TRM)
values, a component of ATC/AFC, document their methodology for determining the TRM values for use in
the TSP’s determination of AFC and ATC.

FERC VRF G1 Discussion
FERC VRF G2 Discussion

FERC VRF G3 Discussion

FERC VRF G4 Discussion

FERC VRF G5 Discussion

VRF and VSL Justifications

As noted above, because ATC/AFC do not directly control the reliable operation of the Bulk-Power System,
a VRF of Lower is appropriate. Furthermore, the proposed VRF is consistent with the VRF for the FERC
approved version of MOD-008-1, which is Lower for TOPs that maintain TRM.
Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
Requirement R4 contains one VRF for the single obligation for a TOP that determines TRM to document its
methodology to determine TRM.
Guideline 3- Consistency among Reliability Standards
The proposed Lower VRF is consistent with the Lower VRF in FERC approved MOD-008-1, which requires
TOPs that maintain TRM to prepare and keep current a TRMID. MOD-008-1 will be retired upon approval
of MOD-001-2. There are no other standards addressing this issue.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective, to ensure that a TOP documents its TRM methodology in
an implementation document and ensure the document reflects current practices. Therefore, the
requirement has one VRF for its single obligation.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R4
Proposed VSL
Lower
None.

Moderate
None.

High
None.

Severe
Each Transmission Operator that
determines TRM values did not
develop a TRMID describing its
method for determining TRM
values.
OR
Each Transmission Operator that
determines TRM values did not
reflect its current practices for
determining TRM values in its
TRMID.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R4
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is binary, and therefore, a single severe VSL is necessary.
Guideline 2b:
The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in the
determination of similar penalties for similar violations.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R4
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications – MOD-001-2, Requirement R5
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The purpose of the requirement is for a TSP or TOP to provide or clarify an element of its TFC or TTC
methodology, ATCID, CBMID, or TRMID, within 45 days of a request. The Lower VRF is appropriate
because the failure for a TOP or TSP to respond to requests on their methodology document(s) in a timely
manner would not put the BES in any immediate risk situation.

FERC VRF G1 Discussion

Guideline 1- Consistency w/ Blackout Report
N/A.

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R5
FERC VRF G2 Discussion
FERC VRF G3 Discussion

FERC VRF G4 Discussion

FERC VRF G5 Discussion

Guideline 2- Consistency within a Reliability Standard
The VRF is applicable to all parts of the requirement.
Guideline 3- Consistency among Reliability Standards
This proposed Lower VRF is consistent with the VRF assigned to similar Reliability Standards, including:
FAC-008-3 Requirement R5, which requires TOs or GOs to provide a response to a requesting registered
entity on its Facility Ratings methodology; FAC-010-2.1 Requirement R5, which requires a Planning
Authority to provide a response to an information request to its System Operating Limit (SOL)
methodology; FAC-011-2 Requirement R5, which requires the Reliability Coordinator to provide a
response to an information request of its SOL methodology; and FAC-013-2 Requirements R3 and R5,
which require a Planning Coordinator to provide a response to an information request of its Transfer
Capability methodology or assessment results.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective, which is information sharing on requests for clarification
of a registered entity’s methodologies and determinations of TTC, TFC, ATC, AFC, CBM, or TRM. The
requirement has one VRF for its single obligation.
Proposed VSL

Lower

Moderate

High

Severe

Each Transmission Operator or
Transmission Service Provider
did not respond in writing to a
written request by one or more
of the registered entities

Each Transmission Operator or
Transmission Service Provider
did not respond in writing to a
written request by one or more
of the registered entities

Each Transmission Operator or
Transmission Service Provider did
not respond in writing to a written
request by one or more of the
registered entities specified in

Each Transmission Operator or
Transmission Service Provider
failed to respond in writing to a
written request by one or more of

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R5
specified in Requirement R5
within 45 calendar days from
the date of the request, but did
respond in writing within 75
calendar days.

VRF and VSL Justifications

specified in Requirement R5
within 76 calendar days from
the date of the request, but did
respond in writing within 105
calendar days.

Requirement R5 within 106
calendar days from the date of the
request, but did respond in writing
within 135 calendar days.

the registered entities specified in
Requirement R5.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R5
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is not binary.

FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

VRF and VSL Justifications

Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in
the determination of similar penalties for similar violations.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R5
The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications – MOD-001-2, Requirement R6
Proposed VRF

LOWER

NERC VRF Discussion

A VRF of “Lower” is assigned to this requirement.
The purpose of the requirement is for a registered entity to provide data related to its AFC, ATC, TFC, or
TTC determinations to other entities that need such data for their own determinations. The VRF of Lower
is appropriate because a failure for a TOP or TSP to respond to requests for data on their ATC equation
determinations in a timely manner would not put the BES in any immediate risk situation.

FERC VRF G1 Discussion

Guideline 1- Consistency w/ Blackout Report
N/A.
Guideline 2- Consistency within a Reliability Standard
The VRF is consistent for all parts of the requirement.
Guideline 3- Consistency among Reliability Standards

FERC VRF G2 Discussion
FERC VRF G3 Discussion

VRF and VSL Justifications

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R6

FERC VRF G4 Discussion

FERC VRF G5 Discussion

This proposed Lower VRF is consistent with VRFs for similar Reliability Standards, including, FAC-013-2
Requirement R6, which requires Planning Coordinator to provide data to support the assessment results
on transfer simulations within 45 calendar days of a request.
Guideline 4- Consistency with NERC Definitions of VRFs
A violation of this requirement would not be expected to adversely affect the electrical state or capability
of the bulk electric system, or the ability to effectively monitor and control the bulk electric system.
Guideline 5- Treatment of Requirements that Co-mingle More than One Obligation
The proposed requirement has a single objective to ensure that TOPs and TSPs share their data related to
ATC/AFC, TTC/TFC, CBM and TRM determinations with other TOPs and TSPs that need such data to
conduct their own determinations.
Proposed VSL

Lower

Moderate

High

Each Transmission Operator or
Transmission Service Provider
did not respond to a written
request for data by one or
more of the registered entities
specified in Requirement R6 by
making the requested data
available within in 45 calendar
days from the date of the
request, but did respond within
75 calendar days.

Each Transmission Operator or
Transmission Service Provider
did not respond to a written
request for data by one or
more of the registered entities
specified in Requirement R6 by
making data available within 76
calendar days from the date of
the request, but did respond
within 105 calendar days.

Each Transmission Operator or
Transmission Service Provider did
not respond to a written request
by one or more of the registered
entities specified in Requirement
R6 by making data available within
106 calendar days from the date of
the request, but did respond
within 135 calendar days.

VRF and VSL Justifications

Severe
Each Transmission Operator or
Transmission Service Provider
failed to respond to a written
request for data by making data
available to one or more of the
entities specified in Requirement
R6.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R6
FERC VSL G1
Violation Severity Level
Assignments Should Not Have
the Unintended Consequence
of Lowering the Current Level
of Compliance

The VSLs assigned to this requirement do not lower the current levels of compliance.

FERC VSL G2
Violation Severity Level
Assignments Should Ensure
Uniformity and Consistency in
the Determination of Penalties
Guideline 2a: The Single
Violation Severity Level
Assignment Category for
"Binary" Requirements Is Not
Consistent
Guideline 2b: Violation Severity
Level Assignments that Contain
Ambiguous Language

Guideline 2a:
The proposed VSL is not binary.

VRF and VSL Justifications

Guideline 2b: The proposed VSL does not use ambiguous terms, supporting uniformity and consistency in
the determination of similar penalties for similar violations.

Project YYYY-##.# - Project NameATC Revisions (MOD A)

VRF and VSL Justifications – MOD-001-2, Requirement R6
FERC VSL G3
Violation Severity Level
Assignment Should Be
Consistent with the
Corresponding Requirement

The proposed VSL is worded consistently with the corresponding requirement.

The VSLs are based on a single violation, not cumulative violations.
FERC VSL G4
Violation Severity Level
Assignment Should Be Based on
A Single Violation, Not on A
Cumulative Number of
Violations

VRF and VSL Justifications

Standards Announcement
Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Final Ballot Now Open through December 20, 2013
Now Available

A final ballot for MOD-001-2 is open through 8 p.m. Eastern on Friday, December 20, 2013.
Background information for this project can be found on the project page.
Instructions for Balloting

In the final ballot, votes are counted by exception. Only members of the ballot pool may cast a ballot;
all ballot pool members may change their previously cast votes. A ballot pool member who failed to
cast a ballot during the last ballot window may cast a ballot in the final ballot window. If a ballot pool
member does not participate in the final ballot, that member’s vote cast in the previous ballot will be
carried over as that member’s vote in the final ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the
standard by clicking here.
Next Steps

Voting results for the standard will be posted and announced after the ballot window closes. If
approved, it will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement

Project 2012-05 ATC Revisions (MOD A)
MOD-001-2
Final Ballot Results
Now Available

A final ballot for MOD-001-2 concluded at 8 p.m. Eastern on Friday, December 20, 2013.
The standard achieved a quorum and sufficient affirmative votes for approval. Voting statistics are listed
below, and the Ballot Results page provides a link to the detailed results for the ballot.

Ballot Results
Quorum: 87.16%
Approval: 86.40%

Background information for this project can be found on the project page.
Next Steps

The standard will be submitted to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Standards Development Process

The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.

For more information or assistance, please contact Wendy Muller (via email),
Standards Development Administrator, or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE
Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

NERC Standards

Newsroom  •  Site Map  •  Contact NERC

Advanced Search

User Name

Ballot Results

Ballot Name: Project 2012-05 ATC Revisions MOD A (MOD-001-2)

Password

Ballot Period: 12/11/2013 - 12/20/2013
Ballot Type: Final Ballot

Log in

Total # Votes: 319

Register

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Total Ballot Pool: 366
Quorum: 87.16 %  The Quorum has been reached
Weighted Segment
86.40 %
Vote:
Ballot Results: A quorum was reached and there were sufficient affirmative votes for approval

 Home Page

Summary of Ballot Results

Affirmative

Negative

Negative
Vote
Ballot Segment
without a
#
#
No
Segment Pool
Weight Votes Fraction Votes Fraction Comment Abstain Vote

1Segment
2Segment
3Segment
4Segment
5Segment
6Segment
7Segment
8Segment
9Segment
10 Segment
10
Totals

1
2
3
4
5
6
7
8
9

105

1

63

0.818

14

0.182

0

19

9

10

0.7

6

0.6

1

0.1

0

1

2

78

1

52

0.867

8

0.133

0

10

8

28

1

15

0.833

3

0.167

0

5

5

81

1

45

0.833

9

0.167

0

12

15

51

1

30

0.811

7

0.189

0

7

7

0

0

0

0

0

0

0

0

0

4

0.3

3

0.3

0

0

0

0

1

2

0.2

2

0.2

0

0

0

0

0

7

0.7

7

0.7

0

0

0

0

0

366

6.9

223

5.962

42

0.938

0

54

47

Individual Ballot Pool Results

https://standards.nerc.net/BallotResults.aspx?BallotGUID=1ce819c7-ae55-43ca-8c4b-b1614c80963b[12/23/2013 10:50:05 AM]

NERC Standards

Segment

Organization

Ballot

Member

1
1

Ameren Services

Vijay Sankar
Eric Scott

1

American Electric Power

Paul B Johnson

1

American Transmission Company, LLC

Andrew Z Pusztai

1

Arizona Public Service Co.

Robert Smith

1
1
1
1
1
1
1
1

Associated Electric Cooperative, Inc.
ATCO Electric
Austin Energy
Avista Utilities
Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Bonneville Power Administration

John Bussman
Glen Sutton
James Armke
Heather Rosentrater
Kevin Smith
Christopher J Scanlon
Patricia Robertson
Donald S. Watkins

1

Brazos Electric Power Cooperative, Inc.

Tony Kroskey

1
1
1
1

John C Fontenot
John Brockhan
Michael B Bax
Joseph Turano Jr.

Affirmative
Abstain
Affirmative
Affirmative

Chang G Choi

Affirmative

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Bryan Texas Utilities
CenterPoint Energy Houston Electric, LLC
Central Electric Power Cooperative
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
El Paso Electric Company
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
Gainesville Regional Utilities
Georgia Transmission Corporation

Daniel S Langston
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Pablo Onate
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Richard Bachmeier
Jason Snodgrass

Affirmative
Affirmative

1

Great River Energy

Gordon Pietsch

1
1
1

Hydro One Networks, Inc.
Ajay Garg
Hydro-Quebec TransEnergie
Martin Boisvert
Idaho Power Company
Molly Devine
International Transmission Company Holdings
Michael Moltane
Corp
JDRJC Associates
Jim D Cyrulewski
JEA
Ted Hobson
KAMO Electric Cooperative
Walter Kenyon
Kansas City Power & Light Co.
Jennifer Flandermeyer
Lakeland Electric
Larry E Watt
Lee County Electric Cooperative
John Chin
Lincoln Electric System
Doug Bantam
Long Island Power Authority
Robert Ganley
Lower Colorado River Authority
Martyn Turner
M & A Electric Power Cooperative
William Price
Manitoba Hydro
Nazra S Gladu
MEAG Power
Danny Dees
MidAmerican Energy Co.
Terry Harbour
Minnkota Power Coop. Inc.
Daniel L Inman

1

1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

https://standards.nerc.net/BallotResults.aspx?BallotGUID=1ce819c7-ae55-43ca-8c4b-b1614c80963b[12/23/2013 10:50:05 AM]

NERC
Notes

Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS

Affirmative
Negative

COMMENT
RECEIVED

Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

SUPPORTS
THIRD PARTY
COMMENTS

NERC Standards
1
1
1
1

Andrew J Kurriger
Mark Ramsey
Michael Jones
Cole C Brodine

1
1
1
1
1

Muscatine Power & Water
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy

1

Ohio Valley Electric Corp.

Robert Mattey

1
1
1
1
1
1
1

Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Otter Tail Power Company
Platte River Power Authority

Terri Pyle
Doug Peterchuck
Jen Fiegel
Edward Bedder
Brad Chase
Daryl Hanson
John C. Collins

1

Portland General Electric Co.

John T Walker

1
1
1

Brenda L Truhe
Laurie Williams
Kenneth D. Brown

1
1
1
1
1
1
1
1
1
1
1
1

PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
SaskPower
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Carolina Public Service Authority

1

Southern California Edison Company

Steven Mavis

1
1
1
1
1
1
1
1
1
1
1
1
1

Southern Company Services, Inc.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Texas Municipal Power Agency
Trans Bay Cable LLC
Tri-State G & T Association, Inc.
U.S. Bureau of Reclamation
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

2

BC Hydro

2
2
2
2
2
2
2
2
2

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.

Robert A. Schaffeld
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Brent J Hebert
Steven Powell
Tracy Sliman
Richard T Jackson
Jonathan Appelbaum
Allen Klassen
Lloyd A Linke
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung

1

1

Affirmative
Abstain
Affirmative

Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Julaine Dyke
John Canavan

Dale Dunckel
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Will Speer
Wayne Guttormson
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Shawn T Abrams

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative

SUPPORTS
THIRD PARTY
COMMENTS

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS

Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS

Affirmative
Negative
Negative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative

Affirmative
Affirmative
SUPPORTS

https://standards.nerc.net/BallotResults.aspx?BallotGUID=1ce819c7-ae55-43ca-8c4b-b1614c80963b[12/23/2013 10:50:05 AM]

NERC Standards
3

AEP

Michael E Deloach

Negative

3
3
3
3
3
3
3
3

Alabama Power Company
Ameren Services
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy

Robert S Moore
Mark Peters
Chris W Bolick
Scott J Kinney
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

3

City of Bartow, Florida

Matt Culverhouse

Negative

3

City of Clewiston

Lynne Mila

Negative

3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

City of Farmington
City of Redding
City of Tallahassee
Cleco Corporation
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
CPS Energy
Detroit Edison Company
Dominion Resources, Inc.
Entergy
FirstEnergy Corp.
Florida Municipal Power Agency
Florida Power & Light Co.
Florida Power Corporation
Georgia System Operations Corporation

Linda R Jacobson
Bill Hughes
Bill R Fowler
Michelle A Corley
Charles Morgan
John Bee
Peter T Yost
Jose Escamilla
Kent Kujala
Connie B Lowe
Joel T Plessinger
Cindy E Stewart
Joe McKinney
Summer C Esquerre
Lee Schuster
Scott McGough

3

Great River Energy

Brian Glover

3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

Hydro One Networks, Inc.
Imperial Irrigation District
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
National Grid USA
Nebraska Public Power District
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
Platte River Power Authority
PNM Resources

David Kiguel
Jesus S. Alcaraz
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Mike Anctil
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Roger Brand
Thomas C. Mielnik
Jack W Savage
John S Bos
Brian E Shanahan
Tony Eddleman
David R Rivera
Skyler Wiegmann
Ramon J Barany
David McDowell
Donald Hargrove
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Terry L Baker
Michael Mertz

3

Portland General Electric Co.

Thomas G Ward

3
3

Public Service Electric and Gas Co.
Puget Sound Energy, Inc.

Jeffrey Mueller
Erin Apperson

https://standards.nerc.net/BallotResults.aspx?BallotGUID=1ce819c7-ae55-43ca-8c4b-b1614c80963b[12/23/2013 10:50:05 AM]

THIRD PARTY
COMMENTS

SUPPORTS
THIRD PARTY
COMMENTS
SUPPORTS
THIRD PARTY
COMMENTS

Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative

SUPPORTS
THIRD PARTY
COMMENTS

Abstain
Affirmative
Affirmative
Negative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Negative
Affirmative
Affirmative

SUPPORTS
THIRD PARTY
COMMENTS

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4

Eddy Reece
Thomas M Haire
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Jeff L Neas
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
Gregory J Le Grave
Michael Ibold
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy

4

Rayburn Country Electric Coop., Inc.
Rutherford EMC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Sho-Me Power Electric Cooperative
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Public Service Corp.
Xcel Energy, Inc.
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City of New Smyrna Beach Utilities
Commission
City of Redding

4

City Utilities of Springfield, Missouri

John Allen

4

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative

Tim Beyrle
Nicholas Zettel

Affirmative
Negative

4
4
4
4

Constellation Energy Control & Dispatch,
L.L.C.
Consumers Energy Company
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency

4

Fort Pierce Utilities Authority

Cairo Vanegas

4
4
4
4
4
4
4

Guy Andrews
Herb Schrayshuen
Christopher Plante
Joseph DePoorter
Spencer Tacke
Douglas Hohlbaugh
Henry E. LuBean

Affirmative
Affirmative
Abstain
Affirmative

John D Martinsen

Affirmative

4
4
4
4
4
4
4
4

Georgia System Operations Corporation
Herb Schrayshuen
Integrys Energy Group, Inc.
Madison Gas and Electric Co.
Modesto Irrigation District
Ohio Edison Company
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Utility Services, Inc.
Wisconsin Energy Corp.
WPPI Energy

Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Brian Evans-Mongeon
Anthony Jankowski
Todd Komplin

Affirmative
Affirmative
Affirmative

5

AEP Service Corp.

Brock Ondayko

5
5
5
5
5

Amerenue
Sam Dwyer
Arizona Public Service Co.
Scott Takinen
Associated Electric Cooperative, Inc.
Matthew Pacobit
Avista Corp.
Steve Wenke
BC Hydro and Power Authority
Clement Ma
Boise-Kuna Irrigation District/dba Lucky peak
Mike D Kukla
power plant project
Bonneville Power Administration
Francis J. Halpin
Brazos Electric Power Cooperative, Inc.
Shari Heino
BrightSource Energy, Inc.
Chifong Thomas
City and County of San Francisco
Daniel Mason
City of Austin dba Austin Energy
Jeanie Doty
City of Redding
Paul A. Cummings

4

4

5
5
5
5
5
5
5

Margaret Powell

Abstain

Tracy Goble
Daniel Herring
Russ Schneider
Frank Gaffney

Abstain
Affirmative
Affirmative
Negative
Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=1ce819c7-ae55-43ca-8c4b-b1614c80963b[12/23/2013 10:50:05 AM]

SUPPORTS
THIRD PARTY
COMMENTS

SUPPORTS
THIRD PARTY
COMMENTS

Affirmative
Affirmative

Affirmative
Abstain
Abstain

Negative

Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative

SUPPORTS
THIRD PARTY
COMMENTS

NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Cogentrix Energy Power Management, LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
CPS Energy
Dairyland Power Coop.
Dominion Resources, Inc.
DTE Energy
Duke Energy
El Paso Electric Company
Electric Power Supply Association
Entergy Services, Inc.
Essential Power, LLC
Exelon Nuclear
First Wind
FirstEnergy Solutions
Florida Municipal Power Agency

Karen Webb
Steve Rose
Stephanie Huffman
Mike D Hirst
Kaleb Brimhall
Wilket (Jack) Ng
David C Greyerbiehl
Robert Stevens
Tommy Drea
Mike Garton
Mark Stefaniak
Dale Q Goodwine
Gustavo Estrada
John R Cashin
Tracey Stubbs
Patrick Brown
Mark F Draper
John Robertson
Kenneth Dresner
David Schumann

5

Great River Energy

Preston L Walsh

Negative

5
5
5
5
5
5
5
5
5
5

Roger Dufresne
John J Babik
Brett Holland
Mike Blough
James M Howard
Dennis Florom
Kenneth Silver
Karin Schweitzer
Rick Terrill
S N Fernando

Abstain
Affirmative
Affirmative
Negative
Negative

5
5
5
5
5
5
5
5
5
5

Hydro-Québec Production
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Lower Colorado River Authority
Luminant Generation Company LLC
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
Oglethorpe Power Corporation
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp

5

Portland General Electric Co.

Matt E. Jastram

5
5
5

PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers

Annette M Bannon
Tim Kucey
Steven Grega

5

5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

David Gordon
Steven Grego
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
Bernard Johnson
Henry L Staples
Mahmood Z. Safi
Richard K Kinas
Bonnie Marino-Blair

Affirmative

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain

Abstain
Affirmative
Affirmative
Negative

Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative

Michiko Sell
Lynda Kupfer
Susan Gill-Zobitz
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Edward Magic
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz

https://standards.nerc.net/BallotResults.aspx?BallotGUID=1ce819c7-ae55-43ca-8c4b-b1614c80963b[12/23/2013 10:50:05 AM]

SUPPORTS
THIRD PARTY
COMMENTS

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain

COMMENT
RECEIVED

NERC Standards
5
5
5
5
5

USDI Bureau of Reclamation
Westar Energy
Wisconsin Public Service Corp.
WPPI Energy
Xcel Energy, Inc.

Erika Doot
Bryan Taggart
Scott E Johnson
Steven Leovy
Liam Noailles

6

AEP Marketing

Edward P. Cox

6

Ameren Energy Marketing Co.

Jennifer Richardson

6

APS

Randy A. Young

6
6
6
6
6
6
6
6
6
6
6
6
6
6

Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Colorado Springs Utilities
Con Edison Company of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.

Brian Ackermann
Brenda S. Anderson
Lisa Martin
Marvin Briggs
Robert Hirchak
Shannon Fair
David Balban
David J Carlson
Louis S. Slade
Greg Cecil
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P Mitchell

6

Great River Energy

Donna Stephenson

6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6

Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Luminant Energy
Manitoba Hydro
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
Oklahoma Gas & Electric Services
PacifiCorp
Platte River Power Authority
Power Generation Services, Inc.
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Wisconsin Public Service Corp.
Xcel Energy, Inc.

Massachusetts Attorney General
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities

Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Brenda Hampton
Blair Mukanik
James McFall
John Stolley
Saul Rojas
Steve C Hill
Joseph O'Brien
Jerry Nottnagel
Kelly Cumiskey
Carol Ballantine
Stephen C Knapp
Elizabeth Davis
Peter Dolan
Hugh A. Owen
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Lujuanna Medina

Affirmative
Negative
Abstain

John J. Ciza

Affirmative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Affirmative
Negative

Peter H Kinney

Affirmative

6
6
6
6
6
6
6
6
8
8
8
8
9

Abstain
Affirmative
Abstain

Negative

SUPPORTS
THIRD PARTY
COMMENTS

Negative

COMMENT
RECEIVED

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

David Hathaway
David F Lemmons
Edward C Stein
Roger C Zaklukiewicz
Frederick R Plett
Terry Volkmann

Affirmative
Affirmative
Affirmative

Donald Nelson

Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=1ce819c7-ae55-43ca-8c4b-b1614c80963b[12/23/2013 10:50:05 AM]

Abstain
Abstain

SUPPORTS
THIRD PARTY
COMMENTS

NERC Standards
9
10
10
10
10
10
10
10

National Association of Regulatory Utility
Commissioners
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council

Diane J Barney

Affirmative

Linda Campbell
Russel Mountjoy
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Joseph W Spencer
Steven L. Rueckert

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Legal and Privacy
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Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA  30326
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A New Jersey Nonprofit Corporation

https://standards.nerc.net/BallotResults.aspx?BallotGUID=1ce819c7-ae55-43ca-8c4b-b1614c80963b[12/23/2013 10:50:05 AM]

Exhibit H
Standard Drafting Team Roster for Project 2012-05 ATC Revisions

Drafting Team Roster
Project 2012-05 ATC Revisions
As of August 22, 2013

Position

Participant

Entity

Chair

Aaron Staley

Orlando Utilities Commission

Vice-Chair

Michael Lowman

Duke Energy

Member

David Dockery

AECI

Member

Ryan Harrigill

SPP

Member

Marilyn Jayachandran

PJM

Member

Ross Kovacs

Georgia Transmission Corporation

Member

Sunish Mathew

Southern Company

Member

Tung Nguyen

MISO

Member

James Randall

BPA

Member

Phillip Shafeei

Colorado Springs Utilities

Member

Dede Subakti

CAISO

NERC Staff

Ryan Stewart

NERC

NERC Staff

Valerie Agnew

NERC