RM12-16 FinalRuleSupporting Statement_12_2_2013

FERC-725M (OMB Control No.: 1902-0263)

Docket No. RM12-16, Final Rule issued 9/19/2013

RIN: 1902-AE67

updated 12/2/2013

Supporting Statement

FERC-725M, Mandatory Reliability Standards: Generator Requirements

at the Transmission Interface

Final Rule in Docket No. RM12-16¹

In the Final Rule² in Docket No. RM12-16¹, the Federal Energy Regulatory Commission (Commission or FERC) approves Reliability Standards FAC-001-1 (Facility Connection Requirements), FAC-003-3 (Transmission Vegetation Management), PRC-004-2.1a (Analysis and Mitigation of Transmission and Generation Protection System Misoperations), and PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing), which would replace currently effective Reliability Standards FAC-001-0, FAC-003-1, PRC-004-2a, and PRC-005-1b.

The FAC-001 and FAC-003 standards currently in effect are applicable only to transmission owners and operators. The North American Electric Reliability Corporation (NERC, the Commission-approved Electric Reliability Organization [ERO]) proposed, and FERC approved, extending their applicability to certain generator interconnection facilities (increasing the number of respondents and burden). By contrast, the current versions of PRC-004 and PRC-005 already apply to generator owners as well as transmission owners. Accordingly, the modifications in Reliability Standards PRC-004-2.1a and PRC-005-1.1b merely clarify that their requirements extend not only to protection systems associated with the generating facility or station itself, but also to any protection systems associated with the generator interconnection facilities.

1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

On August 8, 2005, The Electricity Modernization Act of 2005, which is Title XII of the Energy Policy Act of 2005 (EPAct 2005), was enacted into law.³ EPAct 2005 added a new section 215 to the Federal Power Act (FPA), which requires a Commission-certified ERO to develop mandatory and enforceable Reliability Standards⁴, which are subject to Commission review and approval. In 2006, the Commission established a process to select and certify an ERO and, subsequently, certified NERC as the ERO. In 2007, as part of Order No. 693, the Commission approved 83 Reliability Standards (covered under FERC-725A) submitted by NERC, including initial versions of Reliability Standards FAC-001, FAC-003, PRC-004, and PRC-005.

More specifically, EPAct gave FERC new authorities (codified in 16 USC 824o) and described expectations of the Commission-approved ERO. FERC may certify one ERO if FERC determines that the ERO:

“(1)has the ability to develop and enforce ... reliability standards that provide for an adequate level of reliability of the bulk-power system; and

(2)has established rules that—

(A)assure its independence of the users and owners and operators of the bulk-power system, while assuring fair stakeholder representation ...

(C)provide fair and impartial procedures for enforcement of reliability standards ...

(D)provide for reasonable notice and opportunity for public comment, due process, openness, and balance of interests in developing reliability standards….”

FERC has jurisdiction within the U.S. over the ERO and “any regional entities, and all users, owners and operators of the bulk-power system... for purposes of approving reliability standards established under this section and enforcing compliance with this section. All users, owners and operators of the bulk-power system shall comply with reliability standards that take effect under this section.”

FERC’s options when deciding on standards submitted by the ERO. EPAct specifies the Commission’s possible options when deciding on proposed standards submitted by the ERO for FERC review and approval.

FERC “may approve, by rule or order, a proposed reliability standard or modification to a reliability standard if it determines that the standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest. The Commission shall give due weight to the technical expertise of the Electric Reliability Organization with respect to the content of a proposed standard or modification to a reliability standard ..., but shall not defer with respect to the effect of a standard on competition. A proposed standard or modification shall take effect upon approval by the Commission....

…The Commission shall remand to the Electric Reliability Organization for further consideration a proposed reliability standard or a modification to a reliability standard that the Commission disapproves in whole or in part.

…The Commission, upon its own motion or upon complaint, may order the Electric Reliability Organization to submit to the Commission a proposed reliability standard or a modification to a reliability standard that addresses a specific matter if the Commission considers such a new or modified reliability standard appropriate to carry out this section....”

If approved by FERC, Reliability Standards may be enforced either by the ERO (subject to Commission oversight) or by the Commission independently.

Final Rule in RM12-16

In several fact-specific cases on appeal from a NERC registration determination, the Commission has addressed the need to apply Reliability Standard requirements, otherwise generally applicable to a registered transmission owner or transmission operator, to the owner or operator of a significant generator interconnection facility or tie-line.

Following a fact-specific case, NERC formed an Ad Hoc Group for Generator Requirements at the Transmission Interface (Ad Hoc Group) to address concerns about perceived reliability gaps associated with generator interconnection facilities. Then in January 2010, NERC began a project that culminated in submitting a request to the Commission on 7/30/2012 to approve the four proposed revised standards pertaining to generator interconnection facilities addressed in this final rule.

In this final rule in Docket RM12-16, the Commission approves the revised Reliability Standards (FAC-001-1 (Facility Connection Requirements), FAC-003-3 (Transmission Vegetation Management), PRC-004-2.1a (Analysis and Mitigation of Transmission and Generation Protection System Misoperations), and PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing) which, as NERC states:

Represent an improvement over the currently effective standards because they ensure that there are no reliability gaps in (1) the development of Facility connection requirements when a third party requests interconnection to a Generator Owner Facility and (2) the performance of vegetation management on Bulk Electric System Facilities.⁵

2. HOW, BY WHOM, AND FOR WHAT PURPOSE THE INFORMATION IS TO BE USED AND THE CONSEQUENCES OF NOT COLLECTING THE INFORMATION

In general, information collection and record retention requirements related to Reliability Standards are not submitted to, or retained for audit by, FERC. Rather they are submitted to, or retained for audit by, NERC or the Compliance Enforcement Authority, as specified in each individual Reliability Standard.

FAC-001-1. The modifications for Reliability Standard FAC-001-1 would extend the obligation to document, maintain, and publish interconnection requirements to any generator owner that has an executed agreement with a third party to evaluate the reliability impact of a requested or required interconnection. NERC states that the intent of this modified language is to start the compliance clock when the generator owner executes an agreement to perform the reliability assessment required in FAC-002-1. There is the potential for a reliability gap if FAC-001 is not modified as the reliability impact assessment could be delayed.

FAC-003-3. The modifications in FAC-003-3 would extend NERC’s vegetation management requirements to generator owners with qualifying interconnection facilities, including requirements to create and maintain records related to the generator owner’s vegetation management work plan and performance of inspections. NERC states that:

When it comes to vegetation management, [the qualifying generator interconnection facilities] should be treated as though they are transmission lines; the risk of outages from vegetation located on a right-of-way for a generator-owned line is similar to the risk for Transmission Owners.⁶

The documentation related to vegetation management requirements assists respondents to manage vegetation located on rights-of-way and minimize vegetation encroachments. The documentation further provides a way for auditors to evaluate compliance with this standard. Failure to fill this reliability gap could lead to vegetation-related outages.

3. DESCRIBE ANY CONSIDERATION OF THE USE OF IMPROVED INFORMATION TECHNOLOGY TO REDUCE THE BURDEN AND TECHNICAL OR LEGAL OBSTACLES TO REDUCING BURDEN

The use of current or improved technology and the medium are not covered in Reliability Standards, and are therefore left to the discretion of each respondent. We think that nearly all of the respondents are likely to make and keep related records in an electronic format. Each of the eight Regional Entities has a well-established compliance portal for registered entities to electronically submit compliance information and reports. The compliance portals allow documents developed by the registered entities to be attached and uploaded to the Regional Entity’s portal. Compliance data can also be submitted by filling out data forms on the portals. These portals are accessible through an internet browser password protected user interface.

4. DESCRIBE EFFORTS TO IDENTIFY DUPLICATION AND SHOW SPECIFICALLY WHY ANY SIMILAR INFORMATION ALREADY AVAILABLE CANNOT BE USED OR MODIFIED FOR USE FOR THE PURPOSE(S) DESCRIBED IN INSTRUCTION NO. 2

The information collection requirements are unique to these Reliability Standards and to this information collection. The Commission does not know of any duplication in the requirements.

5. METHODS USED TO MINIMIZE THE BURDEN IN COLLECTION OF INFORMATION INVOLVING SMALL ENTITIES

Small entities are expected to see a small increase in burden due to the revised requirements in the revised Reliability Standards.

In general, small entities may reduce their burden by taking part in a joint registration organization or a coordinated functional registration. These options allow an entity to share its compliance burden with other entities.

6. CONSEQUENCE TO FEDERAL PROGRAM IF COLLECTION WERE CONDUCTED LESS FREQUENTLY

There is the potential for a reliability gap if FAC-001 is not modified (to FAC-001-1) because the reliability impact assessment could be delayed. One industry commenter notes that the information required under Reliability Standard FAC-001-1, Requirement R3.1 enhances ITC’s ability to maintain safe and reliable transmission service, and will be useful in its and other ISOs’/RTOs’ transmission planning processes as it will allow them to account for any third party interconnections and their impacts on the overall transmission system.⁷

Failure to follow requirements and compliance of FAC-003-3 could lead to additional sustained power outages due to tree-line contact. These types of failures could jeopardize system reliability. Vegetation contact with transmission lines was a major factor in two significant blackouts (WECC territory in 1996, and the August 2003 Northeast blackout).

7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION

Depending on the timing and details of a particular audit or investigation, some entities may have to retain information for longer than three years. Generally the requirements comply with the OMB guidelines because the data are retained only from the last audit (approximately every 3 years), unless otherwise specified.

These special circumstances are necessary to ensure reliability on the Bulk-Power System.

The standards’ requirements for record retention and quarterly reports follow.

FAC-001-1

“1.3. Data Retention

The Transmission Owner shall keep data or evidence to show compliance as identified

below unless directed by its Compliance Enforcement Authority to retain specific

evidence for a longer period of time as part of an investigation:

• The Transmission Owner shall retain evidence of Requirement R1, Measure M1,

Requirement R3, Measure M3, and Requirement R4, Measure M4 from its last

audit.

The Generator Owner shall keep data or evidence to show compliance as identified

below unless directed by its Compliance Enforcement Authority to retain specific

evidence for a longer period of time as part of an investigation:

• The Generator Owner shall retain evidence of Requirement R2, Measure M2, and

Requirement R3, Measure M3 from its last audit.

The Compliance Enforcement Authority shall keep the last audit records and all

requested and submitted subsequent audit records.”

FAC-003-3

“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

where the evidence retention period specified below is shorter than the time since

the last audit, the Compliance Enforcement Authority may ask an entity to

provide other evidence to show that it was compliant for the full time period since

the last audit.

The applicable Transmission Owner and applicable Generator Owner retains data or evidence to show compliance with Requirements R1, R2, R3, R5, R6 and R7, Measures M1, M2, M3, M5, M6 and M7 for three calendar years unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

The applicable Transmission Owner and applicable Generator Owner retains data or evidence to show compliance with Requirement R4, Measure M4 for most recent 12 months of operator logs or most recent 3 months of voice recordings or transcripts of voice recordings, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

If a applicable Transmission Owner or applicable Generator Owner is found noncompliant, it shall keep information related to the non-compliance until found compliant or for the time period specified above, whichever is longer.

The Compliance Enforcement Authority shall keep the last audit records and all

requested and submitted subsequent audit records.”

“1.4 Additional Compliance Information

Periodic Data Submittal: The applicable Transmission Owner and applicable

Generator Owner will submit a quarterly report to its Regional Entity, or the

Regional Entity’s designee, identifying all Sustained Outages of applicable lines

operated within their Rating and all Rated Electrical Operating Conditions as

determined by the applicable Transmission Owner or applicable Generator Owner

to have been caused by vegetation, except as excluded in footnote 2....

The Regional Entity will report the outage information provided by applicable

Transmission Owners and applicable Generator Owners, as per the above,

quarterly to NERC, as well as any actions taken by the Regional Entity as a result

of any of the reported Sustained Outages.”

8. DESCRIBE EFFORTS TO CONSULT OUTSIDE THE AGENCY: SUMMARIZE PUBLIC COMMENTS AND THE AGENCY’S RESPONSE

The ERO process⁸ to develop and establish Reliability Standards is a collaborative process between the ERO, Regional Entities and other industry stakeholders developing, discussing, and reviewing drafts, commenting and voting on the drafts, posting responses to the comments, conducting a final ballot, and submitting the standard and implementation plan to the Board of Trustees (BOT) for adoption and approval. [This process provides several opportunities for review and comment by stakeholders and interested parties.] Then the final proposed standard (if approved by the BOT) is submitted by the ERO to the FERC for review and approval. Upon approval by FERC, the standards are mandatory and enforceable.

In addition, each FERC rulemaking (both proposed and final rules) is published in the Federal Register, thereby providing public utilities and licensees, state commissions, Federal agencies, and other interested parties an opportunity to submit data, views, comments or suggestions concerning the collection of data.

The proposed rule in RM12-16 was issued on 4/18/2013 and published in the Federal Register on 4/24/2013 (78 FR 24101). As a result of the NOPR, the Commission received ~15 comments and reply comments. The comments are available in the FERC’s eLibrary General and Advanced searches by entering the Docket No. RM12-16. The comments are summarized and addressed in the Final Rule in paragraphs 16-57. No comments were submitted on PRA-related issues including the burden and/or cost of the information collection requirements.

The Final Rule is being published in the Federal Register.

9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS

The Commission does not make payments or provide gifts for respondents related to this collection.

10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS

There are no specific assurances of confidentiality mentioned to respondents.

11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE

This collection does not include any questions of a sensitive nature.

12. ESTIMATED BURDEN OF COLLECTION OF INFORMATION

The burden and cost estimates below are based on the increase in the reporting and recordkeeping burden imposed by the Reliability Standards FAC-001-1 (Facility Connection Requirements) and FAC-003-3 (Transmission Vegetation Management). Our estimate of the number of respondents affected is based on the NERC Compliance Registry as of July 30, 2013. According to the Compliance Registry, NERC has registered 881 generator owners within the United States, and we estimate that approximately 10 percent (or 88) of these generator owners have interconnection facilities that meet the proposed requirements for applicability of the new standard (i.e., having overhead lines that are greater than 200 kV or are part of an IROL or WECC Transfer Path, and that are either longer than one mile or without a clear sightline to the point of interconnection with the host transmission system).⁹

The burden estimates reflect the changes in the standards and the number of affected entities (e.g., the generator owner’s one-time burden to develop, or review and modify, an existing vegetation management program, and the on-going, relatively minor burden of preparing quarterly reports of relevant outages). Estimates for the proposed additional burden imposed in the final rule in RM12-16 by the revised FAC standards follow.

FERC-725M, 1 Final Rule in RM12-16	Number of Respondents10 (1)	Number of Responses per Respondent (2)	Average Burden Hours Per Response (3)	Total Annual Burden Hours (1)x(2)x(3)	Total Annual Cost11
FAC-003-3 (Transmission Vegetation Management)
Strategies, documentation, processes, & procedures (M3)	88	1	32	2,816 (one-time)	$146,432(one-time) [using $52/hr.]
Quarterly Reporting (Compliance 1.4)	96 12	4	0.25	96	$6,720 [using $70/hr.]
Annual Veg. Inspect. Doc. (M6); annual veg. work plan (M7); evidence of mgt. of veg. (M1 & M2), confirmed veg. condition (M4) & corrective action (M5)	88	1	2	176	$12,320 [using $70/hr.]
Record Retention (Compliance 1.2)	88	1	1	88	$2,464 [using $28/hr.]
FAC-001-1 (Facility Connection Requirements)
Facility connection reqs. (R2, R3, M2, & M3)	513	1	16	80 (one-time)	$5,600 (one-time) [using $70/hr.]
Record Retention14	5	1	1	5	$140 [using $28/hr.]
TOTALS
Total, one-time				2,896	$152,032
Total, recurring				365	$21,644
Average Annual Total over Years 1-3 (averaging the one-time burden & cost over 3 years)				1,330	$72,321

First Year. The rule estimates 3,261 hours of burden and $173,676 in the first year (including the one-time implementation cost plus the recurring cost for one year).

Annual estimates, averaging one-time implementation over 3 years. For the submittal to OMB for review under the PRA, this approach will be taken. When averaging the one-time implementation over 3 years, we estimate 1,330 hours per year of burden and $72,321 per year. After year three, the one-time burden hours and associated cost would be removed, leaving only the new recurring burden from this final rule of 365 hours and $21,644 per year. (Note that 93 hours of the estimated recurring annual burden is for record retention requirements; the remaining burden is associated with reporting requirements.)

13. ESTIMATE OF THE TOTAL ANNUAL COST BURDEN TO RESPONDENTS

There is no start-up or other non-labor hour cost associated with the rule.

14. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT

The Regional Entities and NERC do most of the data processing, monitoring and compliance work for Reliability Standards. The associated burden hours, related to this data processing, monitoring, and compliance work performed by NERC and the Regional Entities, is included in FERC-725, OMB Control No. 1902-0225. Any involvement by the Commission is covered under the FERC-725 collection and is not part of this request or package.

The Commission does incur the costs associated with obtaining OMB clearance under the Paperwork Reduction Act for this Collection. FERC estimates the annual cost for this effort to be $2,250¹⁵.

15. REASONS FOR CHANGES IN BURDEN INCLUDING THE NEED FOR ANY INCREASE

In this final rule, the Commission approves the revised Reliability Standards which, as NERC states:

Represent an improvement over the currently effective standards because they ensure that there are no reliability gaps in (1) the development of Facility connection requirements when a third party requests interconnection to a Generator Owner Facility and (2) the performance of vegetation management on Bulk Electric System Facilities.¹⁶

The following table shows the estimated annual burden inventory (averaging implementation over 3 years) for this ‘new’ collection.¹

FERC-725M	Total Request	Previously Approved	Change due to Adjustment in Estimate	Change Due to Agency Discretion
Annual Number of Responses	96	-	-	96
Annual Time Burden (Hr)	1,330	-	-	1,330
Annual Cost Burden ($)	-	-	-	-

The estimated number of generator owners in the NOPR was 89; it has been updated to 88 for the Final Rule to reflect more current industry information. ¹⁰

16. TIME SCHEDULE FOR PUBLICATION OF DATA

There are no data publications as part of this collection

17. DISPLAY OF EXPIRATION DATE

It is not appropriate to display the expiration date because the information is not collected on a preformatted form or in any format that would allow for such a display.

18. EXCEPTIONS TO THE CERTIFICATION STATEMENT

The Commission does not use statistical methods for this collection. Therefore the Commission does not certify that the collection uses statistical methods.

1 In the Notice of Proposed Rulemaking (NOPR) in RM12-16, the associated collection is listed as FERC-725A (OMB Control No. 1902-0244). However, in order to be able to submit the NOPR’s information collection requirements and materials to OMB for PRA review (while other FERC-725A items were pending OMB review or planned for submittal), it was submitted under new FERC-725M instead.

The information collection requirements in this final rule in RM12-16 are also being submitted to OMB for PRA review under FERC-725M. Please note that the existing FAC-001 and FAC-003 standards (and the associated burdens) are included in FERC-725A.

The PRC-004 and PRC-005 standards are also included in FERC-725A. Because the modifications in PRC-004-2.1a and PRC-005-1.1b are merely clarifications of existing requirements, do not extend those existing requirements to any new entity or to additional facilities, and do not affect the existing estimates for burden or respondents related to those standards, those standards and the related burdens will continue to be covered in FERC-725A (and are not included in FERC-725M or this supporting statement).

2 (Order 785, issued 9/19/2013, at http://elibrary.ferc.gov/idmws/common/opennat.asp?fileID=13351817)

3 The Energy Policy Act of 2005 (EPAct), Pub. L. No 109-58, Title XII, Subtitle A, 119 Stat. 594, 941 (2005), codified at 16 U.S.C. 824o (2000).

4 The Federal Power Act (as modified by the EPAct) states “[t]he term “reliability standard” means a requirement, approved by the Commission under this section, to provide for reliable operation of the bulk-power system. The term includes requirements for the operation of existing bulk-power system facilities, including cybersecurity protection, and the design of planned additions or modifications to such facilities to the extent necessary to provide for reliable operation of the bulk-power system, but the term does not include any requirement to enlarge such facilities or to construct new transmission capacity or generation capacity.”

5 See NERC Petition at 4.

6 Id. at 23.

7 Final Rule, RM12-16 at P 21.

8 Details of the ERO’s standard process is available on the NERC website in the Standard Process Manual (Version 3, effective 6/26/2013) at http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf . Figure 1 (Process for Developing or Modifying a Reliability Standard) on page 15 of the NERC manual includes a diagram showing the “typical process for a project identified in the Reliability Standards Development Plan that involves a revision to an existing Reliability Standard....”

9 For Reliability Standard FAC-008-3, OMB Control No. 1902-0244, the Commission estimated that 10 percent of registered generator owners own facilities between the step-up transformer and the point of interconnection, and are not already registered as a transmission owner. That ten percent estimate was not challenged. In this instance, for FAC-003-3, the Commission has used that same ten percent figure even though the percentage of generator owners newly affected by FAC-003-3 will actually be much smaller, because FAC-003-3 applies only to those generator interconnection facilities with overhead lines that are greater than 200 kV or are part of an IROL or WECC Transfer Path, and that are either longer than one mile or without a clear sightline to the point of interconnection with the host transmission system. Thus, the ten percent estimate is a conservative estimate as applied to FAC-003-3.

10 GO = Generator Owner; RE = Regional Entity. The respondents are generator owners, unless otherwise indicated.

In the NOPR, the estimated number of generator owners was 89. For this Final Rule, our estimate of the number of respondents affected is updated and is based on the NERC Compliance Registry as of July 30, 2013. According to the Compliance Registry, NERC has registered 881 generator owners within the United States, and we estimate that approximately 10 percent (or 88) of these generator owners have interconnection facilities that meet the proposed requirements for applicability of the new standard (i.e., having overhead lines that are greater than 200 kV or are part of an IROL or WECC Transfer Path, and that are either longer than one mile or without a clear sightline to the point of interconnection with the host transmission system).

11 The estimates for cost per hour are derived as follows:

• $52/hour, the average of the salary plus benefits for an engineer and a forester, from Bureau of Labor and Statistics at http://bls.gov/oes/current/naics3_221000.htm

• $70/hour, the average of the salary plus benefits for a manager and an engineer, from Bureau of Labor and Statistics at http://bls.gov/oes/current/naics3_221000.htm

• $28/hour, based on a Commission staff study of record retention burden cost.

12The estimated number of respondents (96) includes 88 generator owners, who may be subject to the recordkeeping and reporting burdens of FAC-003 for the first time, and 8 Regional Entities, who may have a slight increase in recordkeeping and reporting requirements due to the increase in entities covered by the vegetation management standard.

13 This estimate is based on the slight possibility that a third party will request to interconnect to a generator interconnection facility in the future. To date, only two generator owners have experienced such a request, Cedar Creek Wind Energy, LLC and Milford Wind Corridor Phase I, LLC, and both have subsequently been registered as transmission owners and transmission operators. See Cedar Creek Wind Energy, LLC, 135 FERC ¶ 61,241, order on reh’g and clarification, 137 FERC ¶ 61,141 (November 17 Order)(2011).

14 Regional Entities may have a de minimis increase in burden due to the increase in the number of entities potentially subject to the revised standard; that burden has been rolled into the estimated Average Burden Hours per Response.

15 This is based on an estimate of work done by the Commission’s Information Clearance team and other FERC staff as well as a non-labor cost related to publishing material in the Federal Register.

16 See NERC Petition at 4

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