RM12-6 Final Rule and RH OMB supporting Statement 5-13-13

FERC-725J, OMB Control No.: 1902-0259

Docket No.: RM12-6/RM12-7, Final Rule: December 20, 2012, and Order on Rehearing: April 18, 2013. RIN: 1902-AE51

Supporting Statement for

FERC‑725J, Definition of the Bulk Electric System

Final Rule and Order on Rehearing in Docket Nos. RM12-6and RM12-7

The Federal Energy Regulatory Commission (Commission or FERC) requests that the Office of Management and Budget (OMB) review and approve FERC‑725J, Definition of the Bulk Electric System, for a three year period. FERC-725J is a new collection and is meant to capture the information collection burden associated with a new definition of the Bulk Electric System.

This information collection consists of four parts:

• System Review and List Creation. In this part Transmission Owners, Generator Owners and Distribution Providers must review their systems and make qualified asset lists.

• Exception Requests. Transmission Owners, Generator Owners and Distribution Providers may submit to NERC and to the applicable Regional Entity requests for inclusion or exclusion of certain elements from the Bulk Electric System.

• Local Distribution Determinations. Transmission Owners, Generator Owners and Distribution Providers may submit a request to FERC for a local distribution determination.

• Implementation Plans and Compliance. Some Transmission Owners, Generator Owners and Distribution Providers will have to come into compliance with certain Reliability Standards and the associated information collection requirements of those Reliability Standards. These entities may need to create implementation plans as they work toward compliance with Reliability Standards.

A. JUSTIFICATION

1. CIRCUMSTANCES THAT MAKE THE COLLECTION OF INFORMATION NECESSARY

On August 8, 2005, The Electricity Modernization Act of 2005 was enacted into law.¹ EPAct 2005 (Energy Policy Act 2005) added a new Section 215 to the FPA which requires a Commission-certified Electric Reliability Organization (ERO) to develop mandatory and enforceable Reliability Standards which are subject to Commission review and approval. Once approved, the Reliability Standards may be enforced by the ERO subject to Commission oversight.

In Order No. 693^{2, 3} the Commission approved 83 of a total 107 proposed Reliability Standards, six of the eight proposed regional differences, and the NERC Glossary of Terms Used in Reliability Standards (NERC Glossary)⁴, which includes NERC’s definition of bulk electric system.⁵ That definition provides:

As defined by the Regional Reliability Organization, the electrical generation resources, transmission lines, interconnections with neighboring systems, and associated equipment, generally operated at voltages of 100 kV or higher. Radial transmission facilities serving only load with one transmission source are generally not included in this definition.⁶

In approving NERC’s definition of bulk electric system, the Commission stated that “at least for an initial period, the Commission will rely on the NERC definition of bulk electric system and NERC’s registration process to provide as much certainty as possible regarding the applicability to and the responsibility of specific entities to comply with the Reliability Standards.”⁷ The Commission also stated that “[it] remains concerned about the need to address the potential for gaps in coverage of facilities.”⁸

Order Nos. 743 and 743-A

On November 18, 2010, the Commission revisited the definition of “bulk electric system” and issued Order No. 743, which directed the ERO, through the ERO’s Reliability Standards Development Process, to revise its definition of the term “bulk electric system” to address the Commission’s technical and policy concerns, including inconsistency in application of the definition and a lack of oversight and exclusion of facilities that are required for the reliable operation of the interconnected transmission network, and to ensure that the definition encompasses all facilities necessary for operating an interconnected electric transmission network, pursuant to Section 215 of the FPA. In Order No. 743, the Commission stated that the best way to address these concerns is to eliminate the Regional Entity discretion to define bulk electric system without ERO or Commission review, maintain a bright-line threshold that includes all facilities operated at or above 100 kV except defined radial facilities, and adopt an exemption process and criteria for excluding facilities that are not necessary to operate an interconnected electric transmission network.⁹ However, Order No. 743 allowed the ERO to “propose a different solution that is as effective as, or superior to, the Commission’s proposed approach in addressing the Commission’s technical and other concerns so as to ensure that all necessary facilities are included within the scope of the definition.”¹⁰ The Commission directed NERC to file the revised definition of bulk electric system and its process to exempt facilities from inclusion in the bulk electric system within one year following the effective date of the final rule.¹¹

In Order No. 743-A, the Commission reaffirmed its determinations in Order No. 743. In addition, the Commission clarified that the specific issue the Commission directed the ERO to rectify is the discretion the Regional Entities have under the current definition to define the parameters of the bulk electric system in their regions without any oversight from the Commission or NERC.¹² The Commission also clarified that it was not the Commission’s intent through its determination regarding “impact-based methodologies” to disrupt the NERC Rules of Procedure or the Statement of Compliance Registry Criteria.¹³ Nor did the Commission intend to rule out using any form of a material impact test in the reliability context that can be shown to identify facilities needed for reliable operation.¹⁴

The Commission further clarified that the statement in Order No. 743, “determining where the line between ‘transmission’ and ‘local distribution’ lies … should be part of the exemption process the ERO develops” was intended to grant discretion to the ERO, as the entity with technical expertise, to develop criteria to determine how to differentiate between local distribution and transmission facilities in an objective, consistent, and transparent manner.¹⁵ With respect to determining which facilities are local distribution for reliability purposes and in response to the rehearing requests, the Commission stated that the “seven factor test” in Order No. 888 could be relevant and possibly is a logical starting point for determining which facilities are local distribution for reliability purposes.¹⁶ However, the Commission left it to NERC in the first instance to determine if and how the seven factor test should be considered in differentiating between local distribution and transmission facilities.¹⁷ Order No. 743-A re-emphasized that local distribution facilities are excluded from the definition of Bulk-Power System and, therefore, must be excluded from the definition of bulk electric system.

Proposed Rule (Docket Nos. RM12-6 & RM12-7)

On January 25, 2012, NERC submitted two separate but contemporaneous petitions pursuant to the directives in Order No. 743, separately presenting (1) NERC’s proposed revision to the definition of bulk electric system and (2) revisions to NERC’s Rules of Procedure to add a procedure for requesting and receiving exceptions from the “bulk electric system” definition. In the NOPR, we addressed both petitions.

Revised Definition of Bulk Electric System

In Docket No. RM12-06-000, NERC filed a petition requesting Commission approval of a revised definition of “bulk electric system” in the NERC Glossary (NERC BES Petition). In the NERC BES Petition, NERC also requests approval of the proposed “Detailed Information to Support an Exception Request,” which will be used in the submittal, review, and approval or disapproval of requests for exceptions from the “bulk electric system” definition. Finally, NERC requests Commission approval of its plan for implementation of the revised definition of “bulk electric system.”

NERC Petition for Approval of Revisions to Rules of Procedure to Adopt a Bulk Electric System Exception Process

In Docket No. RM12-7-000, NERC filed proposed revisions to its Rules of Procedure for the purpose of adopting a procedure for requesting and receiving exceptions from the definition of bulk electric system (NERC ROP Petition). NERC states that the proposed exception process addresses the applicable concerns raised by the Commission, in Order No. 743, with respect to the current processes for determining what facilities are part of the bulk electric system and what facilities are not.¹⁸ NERC also states that the exception process provides for decisions to approve or disapprove exception requests to be made by NERC, rather than by the Regional Entities, thereby eliminating the potential for inconsistency and subjectivity that the Commission was concerned was created by having decisions as to what facilities are included in or excluded from the BES made at the Regional Entity level.¹⁹

NERC states that the exception process establishes a process that (1) balances the need for effective and efficient administration with due process and clarity of expectations; (2) promotes consistency in determinations and eliminates Regional discretion by having all decisions on exception requests made at NERC; (3) provides for involvement of persons with applicable technical expertise in making decisions on Exception Requests; and (4) should alleviate concerns about a “one-size-fits-all” approach.

Final Rule (Docket Nos. RM12-6 & RM12-7)

Pursuant to section 215(d) of the Federal Power Act (FPA),²⁰ the Commission approves modifications to the currently-effective definition of “bulk electric system” developed by the North American Electric Reliability Corporation (NERC), the Commission-certified Electric Reliability Organization (ERO). The Commission finds that the modified definition of “bulk electric system” improves upon the currently-effective definition by establishing a bright-line threshold that includes all facilities operated at or above 100 kV and removing language that allows for broad regional discretion. The modified definition also provides improved clarity by identifying specific categories of facilities and configurations as inclusions and exclusions to the definition of “bulk electric system.”

Highlights of the Final Rule include:

• accepts NERC’s revisions to its Rules of Procedure, which creates an exception procedure to add elements to, or remove elements from, the definition of “bulk electric system” on a case-by-case basis;

• approves NERC’s implementation plan for the revised “bulk electric system” definition;

• approves NERC’s form entitled “Detailed Information to Support an Exception Request” that entities will use to support requests for exception from the “bulk electric system” definition;

• finds that the Commission can designate sub-100 kV facilities, or other facilities, as part of the bulk electric system, provided that the Commission provides opportunity for notice and comment; and

• establishes a process pursuant to which an entity can seek a determination by the Commission whether facilities are “used in local distribution” as set forth in the Federal Power Act.

Order on Rehearing (Docket Nos. RM12-6 & RM12-7)

The Commission received rehearing requests from multiple entities. In the order on rehearing the Commission denies rehearing in part, grants rehearing in part and otherwise reaffirms its determinations in Order No. 773 (Final Rule).

The Commission does not alter any of the information collection requirements in the order on rehearing. However, the Commission does modify some of the estimates, as well as include a collection category (local distribution determinations) that it did not include in the final rule burden estimates.²¹

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

As part of the Final Rule, the Commission requires several action items of industry. Owners of equipment need to review their system to determine which elements are BES under the revised definition and create a list that is available to other parties on request. For any newly identified BES elements, owners and other entities will work together to create implementation plans on timing and requirements that should be met to have new elements fully compliant. The lists and implementation plans should be used by the owners of the equipment, entities where those elements fall under the scope of responsibility, NERC and FERC. For some entities, part of implementation includes coming into compliance with information collection requirements that are part of existing reliability standards.

Exception Requests will be available to owners of elements and entities where the elements are under their scope of responsibility. For Exception Requests, technical data is required to be submitted to provide justification for the request. NERC has final call on each Request and FERC can check NERC material.

FERC will use the information filed for local distribution determinations to decide whether facilities are actually used for local distribution as set forth in the Federal Power Act.

Failure to properly perform system reviews, list creation, exception requests and implementation plans could cause elements needed for BES to not be properly classified and could jeopardize system reliability.

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

Most of the information collection requirements related to the new BES definition do not require industry participants to file information with the Commission. The use of current or improved technology is not covered in the proposed BES definition and is, therefore, left to the discretion of each reporting entity.

Entities filing requests for local distribution determinations may use the Commission’s eFiling system.

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

Presently, no list exists to identify which elements are BES and there is no process to handle Exception Requests. Additionally, the revised definition may bring new elements into the BES and owners need to determine how the new elements will be compliant with the body of standards.

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

Generally, small entities may not have large systems, may not have a significant impact on the BES, or tend to operate at lower voltages. For those small entities that do have critical elements that are included in the BES, their obligation is to meet all the applicable standards with no exceptions. A small entity could pursue an Exception Request to have an element removed and it will be evaluated by the regional entities and NERC.

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

Failure to properly perform system reviews, list creation, exception requests and implementation plans could cause elements needed for BES to not be properly classified and could jeopardize system reliability.

7. EXPLAIN ANY SPECIAL CIRCUMSTANCES RELATING TO THE INFORMATION COLLECTION

Individual reliability standards to which some entities will have to comply may have records retention schedules that exceed OMB guidelines in 5 CFR 1320.5(d)(2)(iv) of not retaining records for longer than three years. The Commission has not prescribed a set data retention period to apply to all Reliability Standards. The Commission is unconvinced that a one-size fits all approach to data retention is appropriate. This is due to different Reliability Standards requiring data retention for shorter or longer periods. The Commission also denies that it should set a data retention requirement for any Reliability Standard for which one is currently lacking. [It should be noted that the industry had developed, vetted, voted on, and proposed the various Reliability Standards including reporting and recordkeeping requirements for review and approval by FERC. Upon approval by FERC, the Reliability Standards become mandatory.]

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

In the filing, NERC and regional entities did not specify any expected costs or number of Exception Requests that would be processed. Staff did have informal conversations with regional entities and review material on their proposed budgets to gain insight into how the revised definition may affect their operation. Since we expect the NPCC region to have largest change, we consulted with a September 2009 report to aid in Staff estimates.

The Proposed Rule sought further public input on proposed bulk electric system definition and on the proposed exception request procedure, including the associated information collection requirements. Several entities commented on items related to the information collection and a summary of these, along with the Commission’s responses are contained below. For a more full treatment of comments on the rule and the Commission’s response please see the Final Rule attached to this package.

Comments

NRECA and APPA²² do not take a position on the estimates but observe that modifications to the proposed definition or directives to NERC may result in substantial changes to the burden estimates and the assessment of whether the which would require the Commission to re-assess its burden and small business impact determinations. Similarly, APPA and WPPC believe that any changes to the proposed definition in the Final Rule that would include additional facilities would cause a significant increase in the reporting burden on the industry. APPA believes that if the Commission were to direct NERC to make revisions to the specific inclusions or exclusions without technical justification, the exception process would quickly become overloaded, with burdens on those seeking exceptions and those ruling on them.

A number of commenters state that the NOPR underestimated the burden of the rulemaking in terms of hours required to comply. APPA believes that the Commission underestimates the information collection costs and the costs of compliance for small utilities. For example, the Commission’s assumption that utility staff would be used to conduct an analysis is not merited in the case of many small entities. APPA states that many of its smaller members do not have the in-house employees and resources to conduct such reliability analyses and would have to rely on outside consultants and legal firms. Therefore, APPA estimates that the fees small utilities would pay for each of the services, based on information and belief, as follows: Consulting Engineer, $225/hour; Record Keeping, $75/hour; and Legal, $500/hour.

Idaho Power contemplates five local network exclusions which contain sixty 100 kV and above lines, and its estimates for the time involved to document these exceptions leads it to believe the Commission is underestimating the number of engineer hours per entity’s responses. According to Idaho Power, based on an initial review of potential exceptions, Idaho Power may seek approximately 9-12 exceptions. Idaho Power agrees with the estimate that transmission owners, generator owners, and distribution providers will experience more significant reporting burdens than other categories of registered entities.

ISO New England believes that there could be a significant burden on planning coordinators and transmission planners which is not addressed in the table shown in the NOPR. ISO New England states that, while it has not performed a similar analysis, it appears that the “Year 1” estimates in the table in the NOPR are significantly understated in view of the resources that it believes will be necessary to establish the initial list. According to ISO New England, the estimate of approximately $13 million expended over the entire system seems overly optimistic. BPA anticipates, based on customer feedback, that the BPA footprint alone will experience several hundred exception requests in the first two years. BPA estimates the additional workload from evaluating the exception requests will be approximately five to six full time equivalents which includes one full time coordinator, a customer service engineer for system verification, a planner to run studies, an operations engineer, and dispatch personnel for real-time system impacts. NYPSC and the Massachusetts DPU contend that the costs of compliance with the definition will be excessive. NYPSC cites to a 2009 report from NERC and NPCC, that the compliance costs would exceed $280 million.

Commission Determination

Commenters raise concerns that modifications to the proposed definition or directives to NERC may result in substantial changes to the burden estimates. While the Commission is requiring one modification to the language in the NERC proposal, the Commission finds that it does not need to reassess the burden estimates because the change is intended to simply make more explicit what NERC and other commenters indicate is the expected application of the proposed definition to a low-voltage, looped system as depicted in figures 3 and 5 of the Final Rule. Therefore, we do not anticipate the one modification to result in a significant change to what elements are considered part of the bulk electric system or applications for case-by-case exceptions. The burden estimates in this Final Rule represent the incremental burden changes related only to increased reporting burden associated with the identification of new bulk electric system elements as a result of the modified definition. Furthermore, we acknowledge that NPCC may be subject to additional reporting requirements, however, the burden estimates are averages for all of the filers. Idaho Power’s observation that the Commission is underestimating the number of engineering hours is not supported by analysis. Similarly, we are not persuaded by ISO New England’s position that there may be a significant burden on planning coordinators and transmission planners associated with proposed definition because it does not offer any analysis to support this assertion. The Commission expects any burden for planning coordinators and transmission planners to be de minimis or incorporated under their existing responsibilities. In any event, Idaho Power and ISO New England did not provide any estimates of the number of hours that it would take to determine exceptions, nor suggest alternative estimates. In response to APPA’s hourly estimates that are higher than the estimates in the NOPR the Commission notes that its hourly rate estimates for the burden estimates are averages for all of the filers and are based on national wage data for utilities obtained from the Bureau of Labor Statistics (for engineers and legal) and NPCC's assessment of Bulk Electric System Definition (for completing implementation plans and compliance), and Commission staff outreach (recordkeeping). Thus, the Commission adopts the burden estimates that it set forth in the NOPR. The Commission disagrees with BPA that there may be a large number of exception requests generated from entities within its footprint that may have to be processed and the significant addition of FTEs. First, BPA has not provided any analysis or evidence to support its claim. Nevertheless, the Commission’s expectation, like NERC’s, is that application of the definition with its inclusions and exclusions should not materially change what is considered part of the bulk electric system today. Thus, the number of exception requests should not be excessive.

Some comments address the potential impact the requirements would have on small entities but did not provide specific estimates on this impact. Because these comments are also the subject of the analysis performed under the Regulatory Flexibility Act, the Commission has provided a response under that section of the rulemaking.

We are not persuaded by NYPSC and Massachusetts DPU that the costs for compliance will be $280 million. First, NYPSC nor Massachusetts do not dispute or address the specific information collection cost estimates in the NOPR. In addition, the vast majority (approximately $234 million) of the costs included in the report to which the commenters cite appear to be capital costs which are not applicable to an information collection estimate. Further, the report does not account for the revised language in the definition of bulk electric system and the specific inclusions and exclusions that we are approving in this Final Rule.

Order on Rehearing. In the Final Rule, the Commission stated that it did not need to reassess the reporting burden estimates and Regulatory Flexibility Act (RFA) certification. NARUC requests that the Commission clarify its RFA analysis in light of its decision to rule on jurisdictional questions and to direct NERC to not permit certain 100 kV and above facilities that are looped with sub-100 kV facilities to qualify for exclusion E1. NARUC maintains that the Commission modified the definition by changing language contained in exclusions E1 and E3, the net effect of which would be to increase the number of entities that might choose to use the exception process. Therefore, according to NARUC, it is likely that the Commission’s actions will impose unjustified regulatory burdens and costs.

NRECA also states that the public reporting burden and information collection requirement section of the Final Rule did not discuss additional costs associated with the Commission making local distribution determinations or entities having to apply for an exception as a result of the Commission’s interpretation of exclusion E1. NRECA also states that the Commission erred by not modifying the RFA certification that the Final Rule will not have a significant economic impact on a substantial number of small entities. NRECA seeks clarification of the Final Rule because it believes that the jurisdiction determination process and the exclusion E1 directive will affect other small entities that were not identified previously, and the Commission must identify affected entities before it can certify the determination. NRECA states that the RFA requires that all effects of a rule on small entities must be considered, not just initial compliance costs or only the costs associated with small entities that identify, for the first time, facilities that are subject to the bulk electric system definition. NRECA requests that the Commission revisit the impact of the Final Rule on small entities, and thereafter clarify and provide greater detail with respect to its RFA certification.

Similarly, APPA states that the Commission’s modifications to the definition will substantially increase the public reporting burden, necessitating a new analysis. APPA argues that the Commission’s changes to exclusions E1 and E3 would substantially increase the number of required studies and exception requests, which necessarily affect the associated paperwork burden estimates. Yet, according to APPA, the Commission has failed to reassess its burden calculations and adjust its estimates which will result in the imposition of unjustified regulatory burdens and costs.

APPA also states that the Commission must reassess its RFA analysis to account for the Commission’s changes to exclusions E1 and E3. According to APPA, many of the entities filing these requests might not currently be on the NERC Compliance Registry or might only be listed as distribution providers or load serving entities. In addition, APPA argues that the Commission estimate of 418 small entities is too low. APPA states that it alone has approximately 330 members on the NERC registry, about 290 of which fall within the definition of a small utility under the relevant Small Business Administration definition.

Commission Determination

The Commission grants rehearing in part and denies rehearing in part. The Commission grants rehearing on the need to reassess the burden estimates relative to the Final Rule modifications regarding exclusions E1 and E3. In revising the information cost estimates, the Commission also included additional costs associated with the local distribution determinations. However, because the Commission grants rehearing on implementing exclusions E1 and E3 and instead directs NERC to modify the definition pursuant to FPA section 215(d)(5) in the Phase 2 process, the Commission will address estimates in connection with that change after NERC submits its proposal.

9. EXPLAIN ANY PAYMENT OR GIFTS TO RESPONDENTS

No payments or gifts have been made to respondents.

10. DESCRIBE ANY ASSURANCE OF CONFIDENTIALITY PROVIDED TO RESPONDENTS

No specific assurance of confidentiality has been mentioned to respondents. The asset lists should be considered Critical Energy Infrastructure Information (CEII)²³ as they may identify critical elements needed for BES and system reliability.

11. PROVIDE ADDITIONAL JUSTIFICATION FOR ANY QUESTIONS OF A SENSITIVE NATURE THAT ARE CONSIDERED PRIVATE.

There are no questions of a sensitive nature that are considered private.

12. ESTIMATED BURDEN OF COLLECTION OF INFORMATION

As noted earlier, the Final Rule will result in entities reviewing systems, creating qualified asset lists, submitting exception requests where appropriate, and some entities complying for the first time with mandatory Reliability Standards with respect to certain facilities. The final rule also specified that entities may seek a local distribution determination from the Commission.

The Commission assumes for the system review and list creation requirement that the burden hours per response will vary by type of entity. The variation is due to the complexity of the system and volume of elements for each type of entity. For example, a generator owner may have less than 100 elements in its system to review while a transmission owner may have in its system thousands of elements to review. While NERC did not specify in its petition exactly what will appear on an entity’s list or a specific format, the Commission expects that such lists would include what elements are included or excluded from the bulk electric system, why such elements are included or excluded and possibly a voltage class for each element.

The following table provides details on the burden estimate. In OMB’s submittal system, we averaged the total hours for the first three years to come up with an annual burden estimate.

Requirement	Number and Type of Entity24 (1)	Number of Responses Per Entity (2)	Average Number of Hours per Response (3)	Total Burden Hours (1)*(2)*(3)
System Review and List Creation25	333 Transmission Owners	1 response	85 (engineer hours)	28,305 Yr 1
	843 Generator Owners	1 response	16 (engineer hours)	13,488 Yr 1
	554 Distribution Providers	1 response	27 (engineer hours)	14,958 Yr 1
Exception Requests26	1,730 total Transmission Owners, Generator Owners and Distribution Providers	0.16474 responses in Yrs 1 and 2	94 (60 engineer hrs, 32 record keeping hrs, 2 legal hrs)	26,790 hrs in Yrs 1 and 2
		0.01156 responses in Yr 3 and ongoing	94 (60 engineer hrs, 32 record keeping hrs, 2 legal hrs)	1,880 hrs in Yr 3 and ongoing
Local Distribution Determinations	8 entities	1 response	92 (60 engineer hrs, 8 record keeping hrs, 24 legal hrs)	736 hrs (all years)
Regional and ERO Handling of Exception Requests27	NERC and 8 Regional Entities	1 response	1,386.67 hrs	12,480 hrs in Yrs 1 and 2
Implementation Plans and Compliance28	111 NPCC Region Registered Entities29	1 response	700 hrs in Yrs 1 and 2*	77,700 hrs in Yrs 1 and 2
		1 response	350 hrs in Yr 3 and ongoing*	38,850 hrs in Yr 3 and ongoing
	75 Registered Entities from 7 other Regions	1 response	700 hrs in Yrs 1 and 2	52,500 hrs in Yrs 1 and 2
		1 response	350 hrs in Yr 3 and ongoing*	26,250 hrs in Yr 3 and ongoing
TOTALS				226,957 hrs in Yr 1
				170,206 hrs in Yr 2
				67,716 hrs in Yr 3 and ongoing

*The numbers marked with an asterisk have been rounded.

FERC projects the annual cost as:

• Year 1: $13,841,400

• Year 2: $10,436,340

• Year 3 and ongoing: $4,310,800 ³⁰

For the first two burden categories above, the loaded (salary plus benefits) costs are: $60/hour for an engineer; $27/hour for recordkeeping; and $106/hour for legal. The breakdown of cost by item and year follows:

• System Review and List Creation (year 1 only): (28,305 hrs + 13,488 hrs + 14,958 hrs) =56,751 hrs * 60/hr = $3,405,060.

• Exception Requests (years 1 and 2): (sum of hourly expenses per request * number of exception requests) = ((60 hrs * $60/hr) + (32 hrs * $27/hr) + (2hrs * $106/hr)) * 285 requests) = $1,332,660.

• Exception Requests (year 3): (sum of hourly expenses per request * number of exception requests) = ((60 hrs * $60/hr) + (32 hrs * $27/hr) + (2 hrs * $106/hr)) * 20 requests) = $93,520.

• Local Distribution Determinations (each year): (sum of hourly expenses per request * number of exception requests) = ((60 hrs*$60/hr) + (8 hrs*$27/hr) + (24 hrs*$106/hr)) * 8 requests) = $50,880.

• Regional and ERO handling of Exception Requests: Between NERC and regional entities we estimate 6 full time equivalent (FTE) engineers will be added at an annual cost of $120,000/FTE ($120,000/FTE * 6 FTE = $720,000). This cost is only expected in years 1 and 2.

• Implementation Plans and Compliance³¹ (years 1 and 2): (hourly expense per entity * hours per response * sum of NPCC and non-NPCC entities) = ($64/hour * 700 hour per response * 186 responses) = $8,332,800.

• Implementation Plans and Compliance (year 3 and beyond): We estimate the ongoing cost for year 3 and beyond, at 50% of the year 1 and 2 costs, to be $4,166,400.

The next table summarizes the burden estimate as it will be submitted to OMB. We are using an average of the burden over the first three years for submittal to OMB [(226,957 hrs + 170,206 hrs + 67,716 hrs)/3 = 154,960].

FERC-725J	Total Request	Previously Approved	Change due to Adjustment in Estimate	Change Due to Agency Discretion
Annual Number of Responses	2,193	-	-	2,041
Annual Time Burden (Hr)	154,960	-	-	154,960
Annual Cost Burden ($)	-	-	-	-

13. ESTIMATE OF THE TOTAL ANNUAL COST BURDEN TO RESPONDENTS

The Commission does not estimate any costs not already associated with the burden hours described in item 12 above.

14. ESTIMATED ANNUALIZED COST TO FEDERAL GOVERNMENT

	Number of Employees (FTEs)	Estimated Annual Federal Cost
Analysis and Processing of filings32	0.12	$17,225
PRA Administration Cost33		$1,588
FERC Total		$18,813

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

The Commission adopts the modified definition of the nation’s bulk electric system which will require an increase in burden. The increase in burden is necessary to ensure that certain facilities needed for the reliable operation of the nation’s bulk electric system are subject to mandatory and enforceable Reliability Standards. As previously described in this supporting statement, entities will be required to review their systems and create lists of qualified assets, file exception requests where necessary, and in some instances, develop an implementation plan and begin complying with certain Reliability Standards. In some instances, an entity may choose to file a request for a local distribution determination with the Commission. In regards to the implementation plan and general reliability standard compliance, the Commission has other information collections currently approved by OMB for specific Reliability Standards. Once respondents are in compliance with the Reliability Standards, the Commission will begin counting the responses for this category under the individual collection for the Reliability Standards. The Commission intends to leave the other information collection elements related to this rulemaking under this collection.

These tasks are deemed necessary in order to maintain the reliable operation of the nation’s bulk electric system.

16. TIME SCHEDULE FOR THE PUBLICATION OF DATA

There is no publication of data associated with this collection of information.

17. DISPLAY OF THE EXPIRATION DATE

It is not appropriate to display the expiration date for OMB approval of the information collected. The information will not be collected on a standard, preprinted form which would avail itself to that display.

18. EXCEPTIONS TO THE CERTIFICATION STATEMENT

We do not display the expiration date as explained in response to item 17 above. In addition, that data collected for this reporting requirement is not used for statistical purposes.

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

2 March 16, 2007

3 Pursuant to section 215(d) of the FPA

4 http://www.nerc.com/files/Glossary_of_Terms.pdf

5 See Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053 (2007).

6 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 75 n.47 (quoting NERC’s definition of “bulk electric system”).

7 Id. P 75; see also Order No. 693-A, 120 FERC ¶ 61,053 at P 19 (“the Commission will continue to rely on NERC’s definition of bulk electric system, with the appropriate regional differences, and the registration process until the Commission determines in future proceedings the extent of the Bulk-Power System”).

8 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 77 (footnotes omitted). For example, the Commission noted that some regional definitions of bulk electric system exclude facilities below 230 kV and transmission lines that serve Washington, DC and New York City, and the Commission stated its intent to address this matter in a future proceeding. Id.

9 Order No. 743, 133 FERC ¶ 61,150 at P 16.

10 Id.

11 Id. P 113.

12 Id. P 11.

13 Id. P 47.

14 Id.

15 Id. P 67.

16 Id. P 69.

17 Id. P 70.

18 NERC ROP Petition at 4

19 Id.

20 16 U.S.C. 824o(d) (2006).

21 The requirements for local distribution determinations were included in the final rule, just not as part of the burden estimates in the final rule.

22 For a full list of the commenters and abbreviations see Appendix A of the Final Rule, attached to this clearance package.

23 See http://www.ferc.gov/legal/ceii-foia/ceii.asp for more information regarding CEII.

24 The “entities” listed in this table are describing a role a company is registered for in the NERC registry. For example, a single company may be registered as a transmission owner and generator owner. The total number of companies applicable to this rule is 1,522, based on the NERC registry. The total number of estimated roles is 1,730.

25 This requirement corresponds to Step 1 of NERC’s proposed transition plan, which requires each U.S. asset owner to apply the revised bulk electric system definition to all elements to determine if those elements are included in the bulk electric system pursuant to the revised definition. See NERC BES Petition at 38.

26 From the total 1,730 estimated roles, we estimate an average of 285 requests per year in the first two years (an average of 0.16474 responses per respondent, as indicated). See Order No. 773 at n. 225. Therefore, the estimated total number of hours per year for years 1 and 2, using an average of 285 requests per year, is 26,790 hours. We estimate 20 requests per year in year 3 and ongoing (an average of 0.01156 responses per respondent, as indicated).

27 Based on the assumption of two full-time equivalent employees added to NERC staff and 0.5 full-time equivalent employees added to each region’s staff, each full-time equivalent at $120,000/year (salary + benefits). The Commission assumes that any ongoing burden to process exception requests will be minimal.

28 The Commission does not expect a significant number of registered entities outside of the NPCC region to identify new elements under the revised bulk electric system definition. NERC also states that the other Regional Entities do not expect an extensive amount of newly-included facilities. See NERC BES Petition at 38. “Compliance” refers to entities with new elements under the new bulk electric system definition required to comply with the data collection and retention requirements in certain Reliability Standards that they did not previously have to comply with. This collection captures the burden imposed on entities that have to comply with certain Reliability Standards for the first time. When changes are made to individual Reliability Standards the Commission uses its collections for those particular standards. These are FERC-725A (1902-0244), FERC-725B (1902-0248), FERC-725D (1902-0247), FERC-725E (1902-0246), FERC-725F (1902-0249), FERC-725G (1902-0252), FERC-725H (1902-0256), and FERC-725I (1902-0258).

29 The estimated range of affected NPCC Region Registered Entities is from 66 to 155 entities.

30 See NOPR, 139 FERC ¶ 61,247 at P 135 for the initial estimates. In the summary costs for years 1-3 displayed in the NOPR and final rule, due to a arithmetic error, the Years 1-3 cost estimates should have been $13,474,000, $10,268,560 and $4,259,920, respectively.

31 The cost and hourly burden calculations for this category are based on a past assessment (NPCC Assessment of Bulk Electric System Definition, September 14, 2009.) In that assessment NPCC indicated $8.9 million annually for operations, maintenance and additional costs. We estimated that roughly half of that cost actually relates to information collection burden. Using the resulting figure, we used a composite wage and benefit figure of $64/hour to estimate the hourly burden figures presented in the burden table.

32 Based upon 2012 FTE average salary plus benefits ($143,540)

33 The Commission bases the cost of data clearance on an average of 24 hours per clearance per year. The data clearance cost represents the activities and efforts of FERC staff to comply with the Paperwork Reduction Act of 1995.

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