MOD-031-1 NERC petition (without exhibits)

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 MOD031-1 AND RETIREMENT OF RELIABILITY STANDARDS MOD-016-1.1, MOD-0170.1, MOD-018-0, MOD-019-0.1 AND MOD-021-1
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

Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate 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

May 13, 2014

TABLE OF CONTENTS
I.

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

II.

NOTICES AND COMMUNICATIONS ................................................................................ 6

III. BACKGROUND .................................................................................................................... 6
A.

Regulatory Framework ..................................................................................................... 6

B.

NERC Reliability Standards Development Procedure ..................................................... 7

C.

The Existing MOD C Standards....................................................................................... 8

D.

Procedural History of Proposed Reliability Standard MOD-031-1 ............................... 10

IV. JUSTIFICATION FOR APPROVAL .................................................................................. 12

V.

A.

Basis and Purpose of the Proposed Reliability Standard ............................................... 12

B.

Requirements in the Proposed Reliability Standard ....................................................... 15

C.

Proposed MOD-031-1 Satisfies Outstanding Commission Directives .......................... 25

D.

Enforceability of the Proposed Reliability Standards .................................................... 31
EFFECTIVE DATE .............................................................................................................. 31

VI. CONCLUSION ..................................................................................................................... 32

Exhibit A

Proposed Reliability Standard

Exhibit B

Implementation Plan

Exhibit C

Order No. 672 Criteria

Exhibit D

Mapping Document

Exhibit E

Analysis of Violation Risk Factors and Violation Security Levels

Exhibit F

Summary of Development History and Record of Development

Exhibit G

Standard Drafting Team Roster

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 MOD031-1 AND RETIREMENT OF RELIABILITY STANDARDS MOD-016-1.1, MOD-0170.1, MOD-018-0, MOD-019-0.1 AND MOD-021-1
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 for Commission
approval proposed Reliability Standard MOD-031-1 – Demand and Energy Data. NERC requests
that the Commission approve proposed Reliability Standard MOD-031-1 (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 E), (iii)
the proposed NERC Glossary definitions for the terms Demand Side Management (“DSM”) and
Total Internal Demand, and (iv) the retirement of currently effective Reliability Standards MOD016-1.1, MOD-017-0.1, MOD-018-0, MOD-019-0.1 and MOD-021-1 (the “Existing MOD C
Standards”), as detailed in this Petition.

1

16 U.S.C. § 824o (2006).

2

18 C.F.R. § 39.5 (2014).

3

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).
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-031-1, a summary of the
development history (Exhibit F) 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-031-1, the associated Implementation Plan
and the new and modified NERC Glossary terms on May 7, 2014.
I.

EXECUTIVE SUMMARY
Proposed Reliability Standard MOD-031-1 is designed to replace, consolidate and improve

upon the Existing MOD C Standards in addressing the collection and aggregation of Demand and
energy data necessary to support reliability assessments performed by the ERO and Bulk-Power
System planners and operators.7 The reliability of the Bulk-Power System is dependent on having
an adequate amount of resources and transmission infrastructure available to serve peak Demand
while also maintaining a sufficient margin to address operating events. Accordingly, it is vital for
entities and the ERO, consistent with its statutory obligation,8 to perform reliability studies to
assess resource and transmission adequacy, and identify the need for any Bulk-Power System
reinforcements (e.g., new generation plants or transmission lines) to help ensure the continued

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).

7

Currently effective Reliability Standard MOD-020-0 also relates to the collection of Demand and energy
data, specifically, the provision of interruptible Demand and direct control load management data to System
Operators and Reliability Coordinators. Because Reliability Standard MOD-020-0 applies to the operational time
frame, as opposed to the planning horizon to which the Existing MOD C Standards apply, the proposed Reliability
Standard does not address the issues currently covered by Reliability Standard MOD-020-0 nor is Reliability
Standard MOD-020-0 proposed for retirement. However, the proposed Reliability Standard addresses the
outstanding Commission directive related to MOD-020-0, as discussed below.

8

FPA Section 215(g) requires the ERO to conduct periodic assessments of the reliability and adequacy of
the Bulk-Power System in North America. 16 U.S.C. § 824o(g) (2006).

2

reliable operation of the Bulk-Power System. The purpose of the proposed Reliability Standard is
to provide applicable entities the authority to establish comprehensive data requirements and
reporting procedures for the collection of actual and forecast Demand and energy (i.e., Demand,
Net Energy for Load and Demand Side Management) data necessary to support the development
of reliability assessments.
As explained below, the framework established in proposed MOD-031-1 provides planners
and operators of the Bulk-Power System access to actual and forecast Demand and energy data, as
well as other related information, needed to perform resource adequacy studies. The proposed
Reliability Standard also supports the continued development of the reliability assessments
prepared by the ERO. NERC has the responsibility under Section 215 of the FPA to prepare
assessments of the overall reliability and adequacy of the North American Bulk-Power System.9
NERC prepares seasonal and long-term assessments to examine the current and future reliability,
adequacy and security of the North American Bulk-Power System in accordance with Section 800
of its Rules of Procedure. NERC’s reliability assessments identify notable trends, emerging issues,
and potential concerns regarding future electricity supply, as well as the overall adequacy of the
Bulk-Power System to meet future Demand. These assessments inform industry, policy makers,
and governmental authorities of Bulk-Power System reliability needs and guide their decisions for
the electric industry.
Proposed MOD-031-1 was developed to address Commission directives from Order No.
69310 to modify the Existing MOD C Standards. Consistent with those directives, proposed MOD-

9

16 U.S.C. § 824o(g); 18 C.F.R. § 39.11.

10

Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416 (Apr. 4, 2007),
FERC Stats. & Regs. ¶ 31,242, at PP 1131-1222 (2007), order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053
(2007).

3

031-1 improves upon the Existing MOD C Standard by: (1) streamlining the Reliability Standards
to clarify data collection requirements; (2) including Transmission Planners as applicable entities
that must report Demand and energy data; (3) requiring applicable entities to report weathernormalized annual peak hour actual Demand data from the previous year to allow for meaningful
comparison with forecasted values; and (4) requiring applicable entities to provide an explanation
of, among other things: (i) how their Demand Side Management forecasts compare to actual
Demand Side Management for the prior calendar year and, if applicable, how the assumptions and
methods for future forecasts were adjusted.; and (ii) how their peak Demand forecasts compare to
actual Demand for the prior calendar year with due regard to any relevant weather-related
variations (e.g., temperature, humidity, or wind speed) and, if applicable, how the assumptions and
methods for future forecasts were adjusted. Consistent with FERC’s directives, NERC is also
proposing to revise the definition of Demand-Side Management to include activities or programs
undertaken by any applicable entity, not just a Load Serving Entity or its customers, to achieve a
reduction in Demand.
Proposed Reliability Standard MOD-031-1 consists of four requirements that collectively
help to ensure that the necessary Demand and energy data is available to those entities that perform
reliability assessments, as follows:

4

•

Requirement R1 mandates that each Planning Coordinator11 or Balancing Authority12 that
identifies a need for the collection of Demand and energy data shall develop and issue a
data request for such data from relevant entities in its area. The requirement mandates that
the data request clearly identify: (i) the entities responsible for providing the data; (ii) the
data to be provided by each entity; and (iii) the schedule for providing the data.
Requirement R1 also specifies the type of Demand and energy data that may be requested.

•

Requirement R2 obligates the entities identified in a data request issued pursuant to
Requirement R1 to provide the requested data to their Planning Coordinator or Balancing
Authority, as applicable, pursuant to the format and schedule specified in the data request.

•

Requirement R3 requires that the Planning Coordinator or the Balancing Authority, as
applicable, provide the data collected under Requirement R2 to their Regional Entity, if
requested, to facilitate the ERO’s development of reliability assessments.

•

Requirement R4 requires entities to share their Demand and energy data with any Planning
Coordinator, Balancing Authority, Transmission Planner or Resource Planner that
demonstrates a reliability need for such data, subject to applicable confidentiality,
regulatory or security restrictions. The requirement to share such data helps ensure that
planners and operators of the Bulk-Power System have access to complete and accurate
data necessary to conduct their own resource adequacy assessments.
By providing for consistent documentation and information sharing practices for the

collection and aggregation of Demand and energy data, proposed Reliability Standard MOD-0311 promotes efficient planning practices and supports the identification of needed system
reinforcements. Furthermore, the requirement in the proposed Reliability Standard to report actual
Demand, Net Energy for Load and Demand-Side Management data from the prior year will allow
for comparison to prior forecasts and further contribute to enhanced accuracy of load forecasting
practices. These activities ultimately enhance the reliability of the Bulk Electric System.

11

As provided in the NERC Glossary, a Planning Coordinator is the same functional entity as a Planning
Authority. Both are defined as “[t]he responsible entity that coordinates and integrates transmission facility and
service plans, resource plans, and protection systems.” The Reliability Functional Model uses the phrase “Planning
Coordinator” to refer to such entities while NERC’s registration criteria uses the term “Planning Authority.”
Applicability Section 4.1.1 of the proposed Reliability Standard lists both Planning Coordinators and Planning
Authorities to avoid confusion as to which registered entities are subject to the proposed Reliability Standard. As
explained in Applicability Section 4.1.1, however, the requirements of the proposed Reliability Standard only use
the term “Planning Coordinator.”
12

As explained further below, Planning Coordinators are the entities that collect and aggregate the Demand
and energy data in certain regions while in other regions Balancing Authorities serve that function. The proposed
Reliability Standard does not change those practices.

5

For the reasons discussed herein, NERC respectfully requests that the Commission approve
the proposed Reliability Standard and the new and modified NERC Glossary terms as just,
reasonable, not unduly discriminatory or preferential and in the public interest.
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*
Associate 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.

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]

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 duty of certifying an ERO that would be charged with developing and
enforcing mandatory Reliability Standards, subject to Commission approval. Section 215(b)(1)15
of the FPA states that all users, owners, and operators of the Bulk-Power System in the United

13

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.
14

16 U.S.C. § 824o (2006).

15

Id. § 824(b)(1).

6

States will be subject to Commission-approved Reliability Standards. Section 215(d)(5)16 of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability
Standard.

Section 39.5(a) 17 of the Commission’s regulations requires the ERO to file for

Commission approval 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.
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

16

Id. § 824o(d)(5).

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.

7

Certification Order, the Commission found that NERC’s proposed 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 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.

The Existing MOD C Standards

The Existing MOD C Standards are designed to help ensure that historical and forecasted
Demand and energy data is available for past event validation and future system assessment. In
particular, the Existing MOD C Standards, along with Reliability Standard MOD-020-0, require
the collection of actual and forecast Demand data necessary to analyze the resource needs to serve
peak Demand while maintaining a sufficient margin to address operating events, as follows:
•

MOD-016-1.1 is the umbrella standard that contains the documentation required for the
data collection requirements. Specifically, it requires the Planning Authority and the
Regional Reliability Organization (now referred to as the Regional Entity) to have
documentation identifying the scope and details of the actual and forecast Demand and
load data, and controllable DSM data to be reported for system modeling and reliability
analysis.

•

MOD-017-0.1 provides for the data requirements for actual and forecast peak Demand and
Net Energy for Load. It requires Load Serving Entities, Planning Authorities, and Resource
Planners to annually provide aggregated information on: (1) integrated hourly Demands;
(2) actual monthly and annual peak Demand (MW) and net load energy (GWh) for the
prior year; (3) monthly peak Demand forecasts and net load energy for the next two years
and (4) annual peak demand forecasts (summer and winter) and annual net load energy for
at least five and up to ten years into the future.

•

MOD-018-0 requires Load Serving Entities, Planning Authorities, Transmission Planners
and Resource Planners to submit load data reports that: (1) indicate whether the Demand
data includes the Regional Reliability Organization’s non-members’ Demands and (2)
addresses how assumptions, methods and uncertainties are treated.

8

•

MOD-019-0.1 provides for the collection of Interruptible Demand and Direct Control Load
Management. It requires that Load Serving Entities, Planning Authorities, Transmission
Planners, and Resource Planners annually provide their forecasts of interruptible Demands
and Direct Control Load Management to NERC, the Regional Reliability Organization and
other entities as specified in the documentation required by MOD-016-1.1.

•

MOD-020-0 addresses the need to provide Interruptible Demand and Direct Control Load
Management Data to System Operators and Reliability Coordinators. It requires that each
Load Serving Entity, Planning Authority, Transmission Planner, and Resource Planner
identify its amount of: (1) interruptible Demand and (2) Direct Control Load Management
to Transmission Operators, Balancing Authorities and Reliability Coordinators upon
request.

•

MOD-021-1 requires Load Serving Entities, Transmission Planners, and Resource
Planners to clearly document how they address the Demand and energy effects of DSM
programs. The standard also requires an applicable entity to include information detailing
how DSM measures are addressed in the forecasts of its peak demand and annual Net
Energy for Load in the data reporting procedures required by MOD-016-0.
In Order No. 693, the Commission approved Reliability Standards MOD-016-1.1, MOD-

017-0.1, MOD-018-0, MOD-019-0.1, MOD-020-0, and MOD-021-1 but directed NERC to make,
or consider, the following modifications:
•

Modify MOD-016-1 and MOD-017-0 to “expand the applicability section to include the
Transmission Planner, on the basis that under the NERC Functional Model the
Transmission Planner is responsible for collecting system modeling data, including actual
and forecast load, to evaluate transmission expansion plans.”22

•

Modify MOD-017-0 to require “reporting of temperature and humidity [data] along with
peak load because actual load must be weather normalized for meaningful comparison with
forecasted values.”23 In responding to this directive, FERC stated that the Commission
should address how to treat entities whose load does not vary with temperature and
humidity.24

•

Modify MOD-017-0 “to require reporting of the accuracy, error and bias of load forecasts
compared to actual loads with due regard to temperature and humidity variations.”25

22

Order No. 693 at PP 1232, 1255.

23

Id. at P 1249.

24

Id. at P 1250.

25

Id. at P 1251.

9

•

Modify MOD-017-0 “to add a requirement that addresses correcting forecasts based on
prior inaccuracies, errors and bias.”26

•

Consider whether to modify MOD-017-0 to allow some exceptions to the requirement to
provide hourly Demand data.27

•

Consider whether to modify MOD-018-0 to exclude small entities from complying with
the standard.28

•

Modify MOD-019-0 “to require reporting of the accuracy, error and bias of controllable
load forecasts.”29

•

Modify MOD-019-0 to add a new requirement “that would oblige resource planners to
analyze differences between actual and forecasted demands for the five years of actual
controllable load and identify what corrective actions should be taken to improve
controllable load forecasting for the 10Ǧyear planning horizon.”30

•

Modify MOD-020-0 “to require reporting of the accuracy, error and bias of controllable
load forecasts.”31

•

Modify MOD-021-0 by adding a requirement for the standardization of principles on
reporting and validating DSM program information.32

•

Modify the definition of the term “Demand Side Management” to add to the definition
“any other entities” that undertake activities or programs to influence the amount or timing
of electricity they use.33
D.

Procedural History of Proposed Reliability Standard MOD-031-1

The proposed Reliability Standard was developed as part of NERC Project 2010-04
Demand Data (MOD C), which was formally initiated on July 18, 2013 with the posting of a
Standard Authorization Request along with a draft of proposed Reliability Standard MOD-031-1

26

Id. at P 1252.

27

Order No. 693 at P 1256.

28

Id. at P 1265.

29

Id. at P 1276

30

Id. at P 1277.

31

Id. at P 1287.

32

Id. at P 1298.

33

Id. at P 1232.

10

for a 45-day comment period and ballot. The project arose from an informal development process
that NERC initiated in February 2013 to address the outstanding Commission directives from
Order No. 693 related to Existing MOD C Standards. Participants in this informal process were
industry subject matter experts, NERC staff, and staff from FERC’s Office of Electric Reliability.
The informal group met numerous times between February 2013 and July 2013, both in person
and in conference calls, to discuss the outstanding FERC directives and, given their experience
with the Existing MOD C Standards, ways to improve those standards. The informal group also
conducted industry outreach to obtain feedback on the Existing MOD C Standards.
In discussing these Reliability Standards, the informal participants concluded that there is
a continued need for NERC’s Reliability Standards to address the collection and aggregation of
Demand and energy data to help ensure that registered entities and the ERO continue to have
complete and accurate data necessary for conducting the reliability assessments that are vital to
understanding and identifying the reliability needs of the Bulk-Power System. The informal group
proposed to consolidate the Existing MOD C Standards into a single, more easily understandable
Reliability Standard that responded to Commission directives and comprehensively addressed the
data requirements and reporting procedures in a clear and efficient manner. Because Reliability
Standard MOD-020-0 applies to the operational time frame, as opposed to the planning horizon to
which the Existing MOD C Standards apply, it was not included in the proposed Reliability
Standard nor is it proposed for retirement. The proposed Reliability Standard, however, addresses
the outstanding Commission directive related to MOD-020-0, as discussed below.
Following the July 18, 2013 posting of the Standard Authorization Request along with the
informal participant’s draft of proposed MOD-031-1 for a 45-day formal comment period and
ballot, a standard drafting team was formed. As further described in Exhibit F hereto, drafts of the

11

proposed Reliability Standard were posted for two additional 45-day comment periods and ballots
to address industry comment. The third additional ballot received a quorum of 76.92% and an
approval of 83.40%. The final ballot received a quorum of 80.37% and an approval of 90.00%.
On May 7, 2014, the NERC Board of Trustees approved proposed Reliability Standard MOD-0311, the proposed new and modified definitions used therein, and the retirement of the Existing MOD
C Standard.
IV.

JUSTIFICATION FOR APPROVAL
As discussed below and in Exhibit C, proposed Reliability Standard MOD-031-1 satisfies

the Commission’s criteria in Order No. 672 and is just, reasonable, not unduly discriminatory or
preferential, and in the public interest. The following section provides: (1) the basis and purpose
of the proposed Reliability Standard; (2) a discussion of each of the requirements in the proposed
Reliability Standard; (3) an explanation of how the proposed Reliability Standard satisfies
outstanding Commission directives from Order No. 693; and (4) a discussion of the enforceability
of the proposed Reliability Standard.
A.

Basis and Purpose of the Proposed Reliability Standard

The proposed Reliability Standard serves the vital reliability goal of establishing a
framework for the collection and aggregation of Demand and energy data necessary to support the
development of Bulk-Power System reliability assessments. As noted above, a fundamental test
for determining the reliability of the Bulk-Power System is an assessment of whether there is an
adequate amount of resources available to serve peak Demand while also maintaining a sufficient
margin to address operating events. Planners and operators of the Bulk-Power System, policy
makers, and governmental authorities rely on the results of these assessments to identify system
reinforcements, such as whether to construct new generation or transmission infrastructure, that
are necessary for the continued reliable operation of the Bulk-Power System.
12

Studying whether existing and planned Bulk-Power System resources and transmission
infrastructure are sufficient to meet current and projected future Demand requires the collection
and aggregation of Demand and energy forecasts on a normalized basis from those functional
entities (i.e., Transmission Planners, Balancing Authorities, Load Serving Entities, and
Distribution Providers) that develop such data. A forecast on a normalized basis is a forecast that
has been adjusted to reflect normal weather conditions and is expected on a 50 percent probability
basis, also known as a 50/50 forecast (i.e., there is a 50 percent probability that the actual peak
realized will be either under or over the projected peak).34 These forecasts form the baseline for
assessing resource adequacy and are a significant factor in achieving Reliable Operation.
Additionally, there is a need to obtain historical data to compare past forecasts with the
actual data. Such comparisons are necessary to improve forecasting methods and enhance the
accuracy of the forecasts.

The accuracy of Demand and energy forecasts is vital to the

development of reliability assessments that provide the correct signals to owners and operators of
the Bulk-Power System with respect to resource adequacy. Underestimating load growth and/or
Net Energy for Load can result in insufficient or inadequate generation and transmission facilities
and may cause reliability issues during Real-time operations. Conversely, overestimating load
growth and/or Net Energy for Load can result in over-investment in infrastructure and underutilization of network capacity.
The proposed Reliability Standard is designed to replace, consolidate and improve upon
the Existing MOD C Standards in addressing the collection and aggregation of the actual and
forecast Demand and energy data necessary to perform complete and accurate reliability
assessments. Like the Existing MOD C Standards, proposed Reliability Standard MOD-031-1

34

Normalized forecasts are used to test against more extreme conditions.

13

support both the reliability assessments prepared by the ERO and those prepared by various BulkPower System planners and operators to assess resource adequacy in their areas. The ERO
prepares seasonal and longǦterm assessments of the overall reliability and adequacy of the North
American Bulk-Power System. For these assessments, the ERO divides the Bulk-Power System
into assessment areas, both within and across the boundaries of the eight Regional Entities. The
preparation of these assessments involves the collection and consolidation of data provided by the
Regional Entities, including forecasts for onǦpeak Demand and energy, demand response, resource
capacity, and transmission projects. The Regional Entities currently obtain the Demand and
energy data used in these assessment by requesting the information from the relevant functional
entities pursuant to the Existing MOD C Standards. Proposed Reliability Standard MOD-031-1
continues to require entities to provide their data to Regional Entities, upon request, to facilitate
the EROs reliability assessments.
The proposed Reliability Standard also continues to provide planners and operators of the
Bulk-Power System access to complete and accurate Demand and energy data to allow such
entities to conduct their own resource adequacy analyses.

By providing for consistent

documentation and information sharing practices for Demand and energy data, proposed MOD031-1 promotes efficient planning practices across the industry and supports the identification of
needed system reinforcements.
Proposed Reliability Standard MOD-031-1 improves upon the existing MOD C Standards
by consolidating the five Existing MOD C Standards into a single, streamlined standard that
provides authority for applicable entities to collect Demand and energy data, and related
information to support reliability assessments. The proposed Reliability Standard enumerates the
responsibilities of applicable entities with respect to the provision and/or collection of such data.

14

Proposed Reliability Standard MOD-031-1 also addresses Commission directives from Order No.
69335 to modify the Existing MOD C Standards, as discussed below.
B.

Requirements in the Proposed Reliability Standard

Proposed Reliability Standard MOD-031-1 provides an efficient and enforceable
mechanism for entities that conduct reliability assessments to obtain all of the Demand and energy
data that is necessary to accurately assess resource adequacy. The data subject to the standard falls
into three general categories: (1) Total Internal Demand; (2) Net Energy for Load; and (3) Demand
Side Management. The term “Total Internal Demand” is a new term proposed for inclusion in the
NERC Glossary. The standard drafting team developed the term in response to industry comment
on the proposed Reliability Standard to provide more specificity to the type of Demand data subject
to the Reliability Standard. The proposed definition of “Total Internal Demand” is “[t]he Demand
of a metered system which includes, the Firm Demand, plus any controllable and dispatchable
DSM Load and the Load due to the energy losses incurred within the boundary of the metered
system.”
NERC is also proposing changes to the definition of Demand Side Management, which is
currently defined as: “The term for all activities or programs undertaken by a Load-Serving Entity
or its customers to influence the amount or timing of electricity they use.” NERC proposes to
define “Demand Side Management” as “[a]ll activities or programs undertaken by any applicable
entity to achieve a reduction in Demand.” Consistent with the Commission directive in Order No.
693, the proposed definition for Demand Side Management is not limited to “activities or program
undertaken by Load Serving Entities or its customers” but is expanded to include “activities or

35

Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 72 FR 16416 (Apr. 4, 2007),
FERC Stats. & Regs. ¶ 31,242, at PP 1131-1222 (2007), order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053
(2007).

15

programs undertaken by any applicable entity.”

Additionally, the standard drafting team

determined that to more accurately reflect the purpose of Demand Side Management activities and
programs, the definition should include the phrase “to achieve a reduction in Demand” instead of
“to influence the amount or timing of electricity they use.”
Proposed Reliability Standard MOD-031-1 provides clear expectations for “who” provides
“what” data to “whom” while also providing entities the flexibility to develop data requirements
and reporting procedures that are appropriate to their specific circumstances. Proposed Reliability
Standard MOD-031-1 consists of four requirements, as follows:
•

Requirement R1 mandates that each Planning Coordinator or Balancing Authority that
identifies a need for the collection of Demand and energy data shall develop and issue a
data request for such data from relevant entities in their area. The requirement mandates
that the data request clearly identify: (i) the entities responsible for providing the data; (ii)
the data to be provided by each entity; and (iii) the schedule for providing the data.
Requirement R1 also specifies the type of Demand and energy data that may be requested
under the proposed Reliability Standard.

•

Requirement R2 obligates the entities identified in a data request issued pursuant to
Requirement R1 to provide the requested data to their Planning Coordinator or Balancing
Authority, as applicable, pursuant to the format and schedule specified in the data request.

•

Requirement R3 requires that the Planning Coordinator or the Balancing Authority, as
applicable, provide the data collected under Requirement R2 to their Regional Entity, upon
request, to facilitate the ERO’s development of reliability assessments.

•

Requirement R4 requires entities to share their Demand and energy data with any Planning
Coordinator, Balancing Authority, Transmission Planner or Resource Planner that
demonstrates a reliability need for such data, subject to applicable confidentiality,
regulatory or security restrictions. The requirement to share such data helps ensure that
planners and operators of the Bulk-Power System have access to complete and accurate
data necessary to conduct their own resource adequacy assessments.

The following is a discussion of each of the four requirements in proposed MOD-031-1:
Requirement R1 provides:
R1.

Each Planning Coordinator or Balancing Authority that identifies a need for the collection
of Total Internal Demand, Net Energy for Load, and Demand Side Management data shall
develop and issue a data request to the applicable entities in its area. The data request shall
include: [Violation Risk Factor: Medium] [Time Horizon: Long-term Planning]
16

1.1.

A list of Transmission Planners, Balancing Authorities, Load Serving Entities, and
Distribution Providers that are required to provide the data (“Applicable Entities”).

1.2

A timetable for providing the data. (A minimum of 30 calendar days must be
allowed for responding to the request).

1.3.

A request to provide any or all of the following actual data, as necessary:
1.3.1. Integrated hourly Demands in megawatts for the prior calendar year.
1.3.2. Monthly and annual integrated peak hour Demands in megawatts for the
prior calendar year.
1.3.2.1.If the annual peak hour actual Demand varies due to weather-related
conditions (e.g., temperature, humidity or wind speed), the
Applicable Entity shall also provide the weather normalized annual
peak hour actual Demand for the prior calendar year.
1.3.3. Monthly and annual Net Energy for Load in gigawatthours for the prior
calendar year.
1.3.4. Monthly and annual peak hour controllable and dispatchable Demand Side
Management under the control or supervision of the System Operator in
megawatts for the prior calendar year. Three values shall be reported for
each hour: 1) the committed megawatts (the amount under control or
supervision), 2) the dispatched megawatts (the amount, if any, activated for
use by the System Operator), and 3) the realized megawatts (the amount of
actual demand reduction).

1.4.

A request to provide any or all of the following forecast data, as necessary: 1.4.1.
Monthly peak hour forecast Total Internal Demands in megawatts for the next two
calendar years.
1.4.2. Monthly forecast Net Energy for Load in gigawatthours for the next two
calendar years.
1.4.3. Peak hour forecast Total Internal Demands (summer and winter) in
megawatts for ten calendar years into the future.
1.4.4. Annual forecast Net Energy for Load in gigawatthours for ten calendar
years into the future.
1.4.5. Total and available peak hour forecast of controllable and dispatchable
Demand Side Management (summer and winter), in megawatts, under the
control or supervision of the System Operator for ten calendar years into the
future.

1.5.

A request to provide any or all of the following summary explanations, as
necessary:
1.5.1. The assumptions and methods used in the development of aggregated Peak
Demand and Net Energy for Load forecasts.
1.5.2. The Demand and energy effects of controllable and dispatchable Demand
Side Management under the control or supervision of the System Operator.
17

1.5.3. How Demand Side Management is addressed in the forecasts of its Peak
Demand and annual Net Energy for Load.
1.5.4. How the controllable and dispatchable Demand Side Management forecast
compares to actual controllable and dispatchable Demand Side
Management for the prior calendar year and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
1.5.5. How the peak Demand forecast compares to actual Demand for the prior
calendar year with due regard to any relevant weather-related variations
(e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.
Requirement R1 consolidates the requirements from the Existing MOD C Standards related
to the development of data requirements and reporting procedures for Demand and energy data.36
Like Reliability Standard MOD-016-1.1, the Planning Coordinator plays a central role in the
collection and aggregation of Demand and energy data under the proposed Reliability Standard.
It is appropriate to designate the Planning Coordinator as one of the entities to collect the data
because, as described in the NERC Functional Model, it is the functional entity that coordinates,
facilitates, integrates and evaluates transmission facility and service plans, and resource plans
within a Planning Coordinator area and coordinates those plans with adjoining Planning
Coordinator areas.37 Balancing Authorities were also included to reflect that, in certain regions,
Balancing Authorities collect and aggregate Demand and energy data used for reliability

36

Exhibit D to this Petition is a mapping document comparing the existing MOD C Standards to proposed
MOD-031-1.
37

Additionally, the Functional Model states that Planning Coordinators are responsible for the collection of
the following information: transmission facility characteristics and ratings from the Transmission Owners,
Transmission Planners, and Transmission Operators; Demand and energy forecasts, capacity resources, and demand
response programs from Load-Serving Entities, and Resource Planners; generator unit performance characteristics
and capabilities from Generator Owners; and long-term capacity purchases and sales from Transmission Service
Providers.

18

assessments. 38 Requirement R1 was drafted to allow entities to continue their existing data
collection practices.39
Requirement R1 establishes the universe of Demand and energy data that entities may be
compelled to provide under the proposed Reliability Standard and mandates that any requests for
such data contain certain basic elements to help ensure that data is provided in a timely and
accurate manner. When a Planning Coordinator or Balancing Authority issues a data request
pursuant to Requirement R1, the data request must include: (i) a list of entities responsible for
providing the data (the “Applicable Entitles”) (Part 1.1); (ii) the schedule for providing the data,
which can be no less than 30 days from the date of the request (Part 1.2); and (iii) the data to be
provided (Part 1.3-1.5). These elements help to ensure that reporting entities are properly notified
whether they must provide data, what data to provide, and when they must provide the data.
Part 1.1 identifies the functional entities (i.e., Transmission Planners, Balancing
Authorities, Load Serving Entities, and Distribution Providers) that may be required to provide
Demand and energy data under the proposed Reliability Standard. The list of entities tracks the
entities responsible for providing data under the Existing MOD C Standards, except for the
addition of Transmission Planners and the removal of Resource Planners. Transmission Planners
were included because, as the Commission notes in Order No. 693, they are responsible for
collecting, and in some cases developing, system modeling data, including actual and forecast
load, to evaluate transmission expansion plans. In contrast, Resource Planners do not develop any

38

For instance, Balancing Authorities serve this function in the Western Electricity Coordinating Council

region.
39

The standard drafting team concluded that such diversity of practice is acceptable from a reliability
perspective.

19

of the data requested under the proposed Reliability Standard. As such, the standard drafting team
concluded that it was appropriate not to include Resource Planners in the list of entities in Part 1.1.
Parts 1.3-1.5 identify the Demand and energy data, and related information that entities
must provide to support the development of reliability assessments. As explained below, Parts
1.3-1.5 carry forward the data included in the Existing MOD C Standards, as illustrated in Exhibit
D. Compared to the Existing MOD C Standards, however, Parts 1.3-1.5 add specificity and clarity
to the data requirements. Additionally, consistent with Commission directives, Parts 1.3-1.5
expands the list of data that may be requested to help ensure that entities that perform reliability
assessments have all the necessary data to develop complete and accurate assessments.
In particular, Part 1.3 identifies the historical Demand and energy data that entities must
provide upon request. As noted above, the collection of actual Demand and energy data is
necessary to compare past forecasts with the actual data to improve the accuracy of the forecasts.
Subparts 1.3.1, 1.3.2 and 1.3.3 include the data now covered by Reliability Standard MOD-0170.1, Requirements R1.1 and R1.2. Part 1.3 adds specificity to the Existing MOD C Standard by
using the NERC Glossary term for “Demand” and adds clarity by stating that the data to be
provided is for the “prior calendar year” rather than just the “prior year.” Consistent with the
Commission’s directive,40 the standard drafting team added Part 1.3.2.1 to require entities whose
annual peak hour actual Demand varies due to weather-related conditions (e.g., temperature,
humidity or wind speed), to also report the “weather normalized annual peak hour actual Demand
for the prior calendar year.”41 Weather normalized Demand data is actual Demand data that has

40

Order No. 693 at P 1249.

41

For those entities whose load does not vary with temperature, humidity, or other related conditions, there is
no need to require them to report weather normalized data because it would be the same as the actual data reported
under Part 1.3.2.

20

been adjusted to account for weather effects (i.e., what the actual demand would have been under
normal or expected weather conditions). Because weather condition can significantly affect the
level of Demand, it is important to account for weather effects when comparing past Demand
forecasts to the actual Demand. As the Commission recognized in Order No. 693, weather
normalized data allows for meaningful comparison with forecasted values.42
Additionally, the standard drafting team added part 1.3.4 to require the reporting of
“monthly and annual peak hour controllable and dispatchable Demand Side Management under
the control or supervision of the System Operator” for the prior calendar year. The standard
drafting team concluded that such data is necessary to analyze the “accuracy, error and bias of
controllable load forecasts,” consistent with the Commission’s directive. 43

The phrase

“controllable and dispatchable Demand Side Management” was used so as to have a single phrase
throughout the proposed Reliability Standard that would cover both Interruptible Demand as well
as Direct Control Load Management.44
Part 1.4 identifies the forecast Demand and energy data that must be provided upon request.
As noted above, the forecast data identified in Part 1.4 forms the baseline for assessing resource
adequacy. Subparts 1.4.1 through 1.4.4 include the data now covered by Reliability Standard
MOD-017-0.1, Requirements R1.3 and R1.4, and Subpart 1.4.5 includes the data now covered by
MOD-019-0, Requirement R1. Part 1.4 adds specificity and clarity to the Existing MOD C
Standard by: (1) using the newly defined phrase “Total Internal Demand” in Parts 1.4.1 and 1.4.3

42

Order No. 693 at P 1249.

43

Id. at P 1276.

44
Interruptible Demand is defined as “Demand that the end-use customer makes available to its Load-Serving
Entity via contract or agreement for curtailment.” Direct Control Load Management (“DCLM”) is defined as
“Demand-Side Management that is under the direct control of the system operator. DCLM may control the electric
supply to individual appliances or equipment on customer premises. DCLM as defined here does not include
Interruptible Demand.” The phrase controllable and dispatchable Demand Side Management is broad enough to
cover both defined terms.

21

instead of the word “demand” so as to more specifically describe the Demand data to be forecasted;
and (2) using the phrase “controllable and dispatchable Demand Side Management…under the
control and supervision of the System Operator” instead of “interruptible demands and Direct
Control Load Management (DCLM),” for the reasons noted above; and (3) clarifying that the
forecasts are for “calendar years.”
Part 1.5 identifies the related information that must be provided to enable system planners
and the ERO to better understand and evaluate the forecasts provided pursuant to Part 1.4 of
Requirement R1. Collectively, the information required by Part 1.5 will help to ensure that those
entities that perform reliability assessments have insight into the assumptions, methods and
accuracy of the forecasts underlying the assessments.

Subpart 1.5.1 carries forward the

information now covered by Reliability Standard MOD-018-0, Requirement R1.2. Subparts 1.5.2
and 1.5.3 carry forward the information now covered by Reliability Standard MOD-021-0,
Requirements R1.1 and R1.2, respectively. As explained further below, Subparts 1.5.4 and 1.5.5
address the Commission’s directives to require the reporting of the accuracy, error, and bias of (1)
load forecasts with due regard to temperature and humidity variations, and (2) controllable load
forecasts. 45 These two additional explanations will require forecasting entities to explain the
accuracy, error and bias of their forecasts as well as the steps they have taken to improve their
forecasting methods.
Lastly, Requirement R1 applies when a Planning Coordinator or Balancing Authority
“identifies a need” for the collection of Demand and energy data.” This language is intended to
reflect that certain Planning Coordinators and Balancing Authorities may not need to collect
Demand and energy data through a data request issued pursuant to the proposed Reliability

45

Order No. 693 at PP 1251, 1276.

22

Standard. That is because certain Planning Coordinators and Balancing Authorities obtain the
necessary Demand and energy data through alternative mechanisms or develop the data
themselves. For instance, many Planning Coordinators, such as independent system operators
(“ISOs”) and regional transmission organizations (“RTOs”), collect the necessary data and
information from entities within their footprint pursuant to requirements in their Open Access
Transmission Tariffs. Additionally, ISOs/RTOs are often in a better position to develop the
necessary Demand and energy forecasts or aggregate the historical data than the entities in their
area. Accordingly, the requirement is drafted so as to only require a Planning Coordinator or
Balancing Authority to issue a data request if there is a need to do so.
Requirement R2 provides:
R2. Each Applicable Entity identified in a data request shall provide the data requested by
its Planning Coordinator or Balancing Authority in accordance with the data request
issued pursuant to Requirement R1.
Requirement R2 will ensure that Applicable Entities provide the Demand and energy data
requested by their Planning Coordinator or Balancing Authority, as applicable, pursuant to
Requirement R1. The intent of the requirement is to reinforce and emphasize accountability for
those entities that are in the best position to have and provide the necessary data.
Requirement R3 helps ensure that the Planning Coordinator or, when applicable, the
Balancing Authority, provides the data collected pursuant to Requirement R2 to the Regional
Entity to support the reliability assessments performed by the ERO. Requirement R3 provides:
R3. The Planning Coordinator or the Balancing Authority shall provide the data collected
under Requirement R2 to the applicable Regional Entity within 75 calendar days of
receiving a request for such data, unless otherwise agreed upon by the parties.
The standard drafting team determined that 75 calendar days was an appropriate time frame
for providing the data to the Regional Entity to accommodate the time it would take the Planning

23

Coordinator or Balancing Authority to collect the data from Applicable Entities under
Requirement R2 and then package that data for the Regional Entity.
Requirement R4 requires applicable entities to share their Demand and energy data to help
ensure that planners and operators of the Bulk-Power System have access to complete and accurate
data necessary to conduct their own resource adequacy assessments. The requirement to share
data amongst entities will improve the efficiency of planning practices and ultimately enhance the
reliability of the Bulk-Power System. Requirement R4 provides as follows:
R4. Any Applicable Entity shall, in response to a written request for the data included in
parts 1.3-1.5 of Requirement R1 from a Planning Coordinator, Balancing Authority,
Transmission Planner or Resource Planner with a demonstrated need for such data in
order to conduct reliability assessments of the Bulk Electric System, provide or
otherwise make available that data to the requesting entity. This requirement does not
modify an entity’s obligation pursuant to Requirement R2 to respond to data requests
issued by its Planning Coordinator or Balancing Authority pursuant to Requirement
R1. Unless otherwise agreed upon, the Applicable Entity:
•

shall provide the requested data within 45 calendar days of the written request,
subject to part 4.1 of this requirement; and

•

shall not be required to alter the format in which it maintains or uses the data.

4.1. If the Applicable Entity does not provide data requested under this requirement
because (1) the requesting entity did not demonstrate a reliability need for the
data; or (2) providing the data would conflict with the Applicable Entity’s
confidentiality, regulatory, or security requirements, the Applicable Entity shall,
within 30 calendar days of the written request, provide a written response to the
requesting entity specifying the data that is not being provided and on what basis.
To reduce the burdens associated with data sharing, Requirement R4 sets forth the
following parameters:
•

The only entities that may obtain the data are Planning Coordinator, Balancing Authority,
Transmission Planner or Resource Planner with a demonstrated reliability need for the data
to conduct their own reliability assessments. This will prevent entities from requesting
data for purposes unrelated to reliability.

•

Applicable entities are only required to provide the data included in Parts 1.3-1.5 of
Requirement R1. An applicable entity may voluntarily provide additional data but cannot
be compelled to do so under the proposed requirement.

24

•

Applicable entities are not required to alter the format in which it maintains or uses the
data.

•

Lastly, applicable entities are not required to share data if it conflict with the applicable
entity’s confidentiality, regulatory, or security requirements.
If an applicable entity does not provide some or all of the data requested because (1) the

requesting entity did not demonstrate a reliability need for the data, or (2) providing the data would
conflict with the entity’s confidentiality, regulatory, or security requirements, the applicable entity
is required to provide a written response specifying the data that is not being provided and on what
basis. This requirement will help ensure that applicable entities do not unjustifiably withhold data.
C.

Proposed MOD-031-1 Satisfies Outstanding Commission Directives

As noted, Project 2010-04 Demand Data (MOD C) was initiated to address outstanding
FERC directives from Order No. 693. The following is a discussion of each of those directives
and the manner in which proposed MOD-031-1 addresses those directives.
Applicability to Transmission Planners: The Commission directed NERC to modify
MOD-016-1 and MOD-017-0 to expand the applicability section to include Transmission Planner
because under the NERC Functional Model the Transmission Planner is responsible for collecting
system modeling data, including actual and forecast load, to evaluate transmission expansion
plans.46 Consistent with this directive, Transmission Planners are included in the applicability
section of proposed MOD-031-1 and, pursuant to Requirement R2, are required to provide
Demand and energy data upon request.
Definition of Demand Side Management: The Commission directed NERC “to add to its
definition of DSM ‘any other entities’ that undertake activities or programs to influence the amount

46

Order No. 693 at PP 1232; 1255.

25

or timing of electricity they use without violating other Reliability Standard Requirement.”47 The
standards drafting team modified the definition of Demand Side Management to be consistent with
FERC’s directive and to add clarity, as discussed above.
Reporting of Temperature and Humidity Data: The Commission directed NERC to modify
MOD-017-0 to require the “reporting of temperature and humidity along with peak load because
actual load must be weather normalized for meaningful comparison with forecasted values.”48 The
Commission stated that collecting this data “will allow all load data to be weatherǦnormalized,
which will provide greater confidence when comparing data accuracy, which ultimately will
enhance reliability.”49 Rather than requiring entities to report actual temperature and humidity
data, however, Subpart 1.3.2.1 requires entities whose peak hour actual Demand varies due to
weather-related conditions (e.g., temperature, humidity or wind speed) to provide their weather
normalized annual peak hour actual Demand for the prior calendar year. The standard drafting
team determined that this approach meets the goal of the Commission’s directive to get weather
normalized data in a more efficient and an equally effective manner. This approach places the
responsibility on each load forecasting entity to weather normalize their Demand data based on
the particular weather conditions that affect their actual Demand. Whereas temperature and
humidity play a large role in some regions, Demand in other regions is more affected by different
weather conditions, such as wind speed. As such, simply requiring the reporting of temperature
and humidity data may not provide the aggregators of the data (i.e., Planning Coordinators or
Balancing Authorities) all the necessary information to weather normalize the data. The standard

47

Order No. 693 at P 1232.

48

Id. at P 1249.

49

Id.

26

drafting team concluded that the load forecasting entities are in the best position to effectively
weather normalize their Demand data in a timely manner.
In Order No. 693, the Commission also directed NERC to consider whether to exempt
entities from the reporting of temperature and humidity if their load does not vary with temperature
and humidity.50 Subpart 1.3.2.1 only requires entities to report weather normalized actual demand
data if their Demand varies due to weather-related conditions. For those entities whose load does
not vary with temperature, humidity, or other weather-related conditions, there is no need to
require them to report weather normalized data because it would be the same as the actual data
reported under Part 1.3.2
Reporting of Accuracy, Error and Bias of Load Forecasts Compared to Actual Loads: The
Commission directed NERC to modify MOD-017-0 to “require reporting of the accuracy, error
and bias of load forecasts compared to actual loads with due regard to temperature and humidity
variations.” 51 The Commission stated that “[m]easuring the accuracy, error and bias of load
forecasts is important information for system planners to include in their studies, and also improves
load forecasts themselves.”52 Requirement R1, Subpart 1.5.5 of the proposed Reliability Standard
satisfies this directive by requiring load forecasting entity to explain “[h]ow the peak Demand
forecast compares to actual Demand for the prior calendar year with due regard to any relevant
weather-related variations (e.g., temperature, humidity, or wind speed) and, if applicable, how the
assumptions and methods for future forecasts were adjusted.” These explanations will describe
the accuracy, error and bias of load forecasts, consistent with the Commission’s directive. As

50

Order No. 693 at P 1250.

51

Id. at P 1251.

52

Id.

27

noted by the Commission, this information “is important [] for system planners to include in their
studies, and also improves load forecasts themselves.”53
Correcting Load Forecasts: Consistent with the Commission directive to modify MOD017-0 to “add a Requirement that addresses correcting forecasts based on prior inaccuracies, errors
and bias,” 54 entities are required, pursuant to Subpart 1.5.5 of Requirement R1 to provide an
explanation of “how the assumptions and methods for future forecasts were adjusted” based on a
comparison of peak Demand forecasts and actual Demand for the prior year. This requirement
will promote changes to an entity’s forecasting practices to increase the accuracy of those
forecasts.
Exceptions to Provide Hourly Demand Data: The Commission disagreed with a
“recommendation to allow some exceptions to the requirement [in MOD-017-0] to provide hourly
demand data” but, recognizing that the “metering for some customer classes may not be designed
to provide certain types of data,” directed the ERO to consider this issue in the Reliability
Standards development process.55 The standards drafting team concluded that there should not be
any such exceptions as the reporting of hourly load data is necessary to accurately model the BulkPower System. The proposed Reliability Standard also provides Planning Coordinators and
Balancing Authorities the flexibility to modify their data requests to accommodate the capabilities
of entities in their area.
Small Entities: The Commission directed NERC to consider whether small entities should
be required to comply with MOD-018-0 because their forecasts are not significant for reliability

53

Order No. 693 at P 1251.

54

Id. at P 1252.

55

Id. at P 1256.

28

purposes.56 The standard drafting team concluded that it was not appropriate to categorically
exempt all small entities. Rather, the standard drafting team determined it was more appropriate
to provide Planning Coordinators and Balancing Authorities, the functional entities that have a
broader view of the significance of an entity’s forecast to their area, the discretion as to whether
to require small entities to provide that data. Should a small entity disagree with their Planning
Coordinator or Balancing Authority on the need for such data, the entity may, in its response to
the data request, explain why its forecasts are not significant and request that it not be required to
submit the data prospectively.
Reporting of the Accuracy, Error and Bias of Controllable Load Forecasts:

The

Commission directed NERC to modify MOD-019-0 to add a requirement for the reporting of the
accuracy, error and bias of controllable load forecasts. 57 The Commission stated that “this
requirement will enable planners to get a more reliable picture of the amount of controllable load
that is actually available, therefore allowing planners to conduct more accurate system reliability
assessments.”58 Consistent with the Commission’s directive, Requirement R1, Subpart 1.5.4 of
the proposed Reliability Standard requires entities to explain “[h]ow the controllable and
dispatchable Demand Side Management forecast compares to actual controllable and dispatchable
Demand Side Management for the prior calendar year and, if applicable, how the assumptions and
methods for future forecasts were adjusted.” Additionally, as noted above, Part 1.3.4 requires
entities to submit their actual Demand Side Management data, which will allow for comparison to
prior forecasts.

56

Order No. 693 at P 1265.

57

Id. at P 1276.

58

Id.

29

Analysis of Actual and Forecast Demands for Five Years for Actual Controllable Load:
The Commission directed NERC to add a new requirement to MOD-019-0 that would obligate
Resource Planners to analyze differences between actual and forecasted Demands for the five years
of actual controllable load and identify what corrective actions should be taken to improve
controllable load forecasting for the 10-year planning horizon. 59 The standard drafting team
concluded that the intent of this directive is satisfied by Requirement R1, Subpart 1.5.4, which
requires entities to explain “how the assumptions and methods for future forecasts were adjusted”
based on a comparison of controllable and dispatchable Demand Side Management forecast
forecasts to the actual controllable and dispatchable Demand Side Management for the prior
calendar year. This requirement will promote changes to an entity’s forecasting practices to
increase the accuracy of those forecasts. Additionally, the proposed Reliability Standard requires
entities to submit their actual Demand Side Management data, which will allow for an analysis of
the actual data to prior forecasts.
Standardization of Principles on Reporting and Validating DSM Program Information:
FERC directed NERC to add a requirement to MOD-021-0 for standardization of principles on
reporting and validating Demand Side Management program information. 60 To address this
directive, the proposed Reliability Standard requires applicable entities to provide an explanation
of (1) the Demand and energy effects of Demand Side Management; (2) the manner in which they
forecast Demand Side Management; and (3) how such forecasts are adjusted to account for bias
and errors. (Requirement R 1.5.3). These explanations will, consistent with the Commission’s
directive, allow system planners and operators to understand how Demand Side Management

59

Order No. 693 at P 1277.

60

Id. at P 1298.

30

program information is reported and validated, and, in turn, provide for a consistent and uniform
evaluation of demand response.
D.

Enforceability of the Proposed Reliability Standards

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. Exhibit E provides a detailed review of the
VRFs and VSLs, and the analysis of how the VRFs and VSLs were determined using these
guidelines.
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.61
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, the proposed new and
modified NERC Glossary terms and the retirement of the Existing MOD C Standards, effective on
the first day of the first calendar quarter that is twelve months after Commission approval. This
12-month implementation period is designed to provide applicable entities sufficient time to
transition from compliance with the Existing MOD C Standards to proposed Reliability Standard
MOD-031-0. The standard drafting team concluded that a 12-month implementation period is

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Order No. 672 at P 327 (“There should be a clear criterion or measure of whether an entity is in compliance
with a proposed Reliability Standard. It should contain or be accompanied by an objective measure of compliance
so that it can be enforced and so that enforcement can be applied in a consistent and non-preferential manner.”).

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appropriate as entities will need time to develop new processes or modify their existing processes
to comply with the proposed Reliability Standard.
VI.

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

the proposed Reliability Standard and associated elements included in Exhibit A,
effective as proposed herein;

•

the proposed implementation plan included in Exhibit B;

•

the proposed definitions for the terms Demand Side Management and Total Internal
Demand, effective as proposed herein; and

•

the retirement of the currently effective Reliability Standards MOD-016-1.1, MOD-0170.1, MOD-018-0, MOD-019-0.1 and MOD-021-1, effective as proposed herein.
Respectfully submitted,
/s/ S. Shamai Elstein
Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate 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: May 13, 2014

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