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 Department of Energy Federal Energy Regulatory Commission 18 CFR Part 40
[Docket No. RM16-22-000; Order No. 847]
 AGENCY: Federal Energy Regulatory Commission.
 ACTION: Final rule.
 SUMMARY: The Federal Energy Regulatory Commission (Commission) approves Reliability Standards PRC-027-1 (Coordination of Protection Systems for Performance During Faults) and PER-006-1 (Specific Training for Personnel) submitted by the North American Electric Reliability Corporation (NERC).
 DATES: This rule will become effective August 13, 2018.
 FOR FURTHER INFORMATION CONTACT:  Juan Villar (Technical Information), Office of Electric Reliability, Division of Reliability Standards and Security, 888 First Street NE, Washington, DC 20426, Telephone: (772) 678-6496, 
                        *Juan.Villar@ferc.gov.* Alan Rukin (Legal Information), Office of the General Counsel, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426, Telephone: (202) 502-8502, 
                        *Alan.Rukin@ferc.gov.*


SUPPLEMENTARY INFORMATION: Order No. 847 Final Rule (Issued June 7, 2018) 1. Pursuant to section 215 of the Federal Power Act (FPA), the Commission approves Reliability Standards PRC-027-1 (Coordination of Protection Systems for Performance During Faults) and PER-006-1 (Specific Training for Personnel).[1]
                    
                     The North American Electric Reliability Corporation (NERC), the Commission-certified Electric Reliability Organization (ERO), submitted Reliability Standards PRC-027-1 and PER-006-1 for approval. As discussed below, we determine that Reliability Standard PRC-027-1, which is designed to maintain the coordination of protection systems installed to detect and isolate faults on bulk electric system elements, such that those protection systems operate in the intended sequence during faults, and PER-006-1, which is intended to ensure that personnel are trained on specific topics essential to reliability to perform or support real-time operations of the bulk electric system, improve upon the currently-effective Reliability Standards. In addition, based on the record before us,  we do not adopt the NOPR proposal to direct NERC to modify Reliability Standard  PRC-027-1 to require an initial protection system coordination study to ensure that applicable entities will perform (or have performed), as a baseline, a study demonstrating proper coordination of its protection systems. 2. The Commission also approves the associated violation risk factors, violation severity levels, implementation plans, and effective dates proposed by NERC for Reliability Standards PRC-027-1 and PER-006-1. The Commission further approves the retirement of currently-effective Reliability Standard PRC-001-1.1(ii) (System Protection Coordination) as proposed by NERC. Finally, the Commission approves new and revised definitions submitted by NERC for incorporation in the NERC Glossary for the following terms: (1) “protection system coordination study;” (2) “operational planning analysis;” and (3) “real-time assessment.” [2] I. Background A. Section 215 and Mandatory Reliability Standards 3. Section 215 of the FPA requires a Commission-certified ERO to develop mandatory and enforceable Reliability Standards, subject to Commission review and approval.[3]
                    
                     Once approved, the Reliability Standards may be enforced by the ERO subject to Commission oversight or by the Commission independently.[4]
                    
                     In 2006, the Commission certified NERC as the ERO pursuant to section 215 of the FPA.[5] B. Order No. 693 4. On March 16, 2007, the Commission issued Order No. 693, approving 83 of the 107 Reliability Standards filed by NERC, including Reliability Standard PRC-001-1.[6]
                    
                     In addition, the Commission directed NERC to develop modifications to Reliability Standard PRC-001-1 that: (1) correct the references for Requirements, and [
                        *sic*] (2) include a requirement that upon the detection of failures in relays or protection system elements on the Bulk-Power System that threaten reliable operation, relevant transmission operators must be informed promptly, but within a specified period of time that is developed in the Reliability Standards development process, whereas generator operators must also promptly inform their transmission operators; and (3) clarifies that, after being informed of failures in relays or protection system elements that threaten reliability of the Bulk-Power System, transmission operators must carry out corrective control actions, 
                        *i.e.,*
                         return a system to a stable state that respects system requirements as soon as possible and no longer than 30 minutes after they receive notice of the failure.[7] C. NERC Petition and Reliability Standards PRC-027-1 and PER-006-1 5. On September 2, 2016, NERC submitted a petition seeking Commission approval of Reliability Standards PRC-027-1 and PER-006-1.
                    [8]( print page 27506)
                    NERC stated that the Reliability Standards, new and revised NERC Glossary terms, and the retirement of Reliability Standard PRC-001-1.1(ii) satisfy the Commission's criteria in Order No. 672 and are just, reasonable, not unduly discriminatory or preferential, and in the public interest.[9]
                    
                     NERC explained that the intent of the submitted Reliability Standards and changes to the NERC Glossary are to maintain the coordination of protection systems installed to detect and isolate faults on bulk electric system elements and require registered entities to provide training to their relevant personnel on protection systems and remedial action schemes. NERC asserted that the submitted Reliability Standards are an improvement over currently-effective Reliability Standard PRC-001-1.1(ii) and will ensure that appropriate personnel are trained on protection systems and that protection systems are appropriately studied, coordinated, and monitored. 1. Reliability Standard PER-006-1 6. NERC stated that Reliability Standard PER-006-1 requires generator operators to use a systematic approach to develop and implement training for dispatch personnel at centrally-located dispatch centers.[10]
                    
                     NERC explained that Reliability Standard PER-006-1 will also cover plant personnel who are responsible for real-time control of a generator. NERC maintained that it is appropriate to train plant personnel in the functionality of protection systems and remedial action schemes. NERC observed that Reliability Standard PER-006-1 replaces the phrase “purpose and limitations” used  in Reliability Standard PRC-001-1(ii) with the phrase “operational functionality” to clearly identify the objective of the training.[11]
                    
                     NERC also noted that Reliability Standard PER-006-1 replaces the phrase “applied in its area” in Reliability Standard PRC-001-1.1(ii) with the phrase “that affect the output of the generating facility(ies)  it operates” to properly tailor the scope of the required training. NERC noted that Reliability Standard PER-006-1 does not specify a periodicity for the required training. 2. Reliability Standard PRC-027-1 7. NERC asserted that Reliability Standard PRC-027-1: provides a clear set of Requirements that obligate entities to (1) implement a process for establishing and coordinating new or revised Protection System settings, and (2) periodically study Protection System settings that could be affected by incremental changes in Fault current to ensure the Protection Systems continue to operate in their intended sequence.[12] According to NERC, Reliability Standard PRC-027-1, Requirement R1 mandates that each transmission owner, generator owner, and distribution provider establish a process for developing new and revised protection system settings for bulk electric system elements.[13] 8. NERC stated that Reliability Standard PRC-027-1, Requirement R2 mandates that every six years, applicable entities must either: (1) Perform a protection system coordination study to determine whether the protection systems continue to operate in the intended sequence during faults; (2) compare present fault current values to an established fault current baseline and, only if the comparison identifies a 15 percent or greater deviation in fault current values (either three phase or phase to ground) at a bus to which the bulk electric system is connected, perform a protection system coordination study; or (3) use a combination of Options 1 and 2.[14] 9. NERC explained that Reliability Standard PRC-027-1, Requirement R3 will require applicable entities to use the process established under Reliability Standard PRC-027-1, Requirement R1 for the development of any new or revised protection system settings. 3. Retirement of Reliability Standard PRC-001-1.1(ii) 10. NERC stated that Reliability Standard PRC-001-1.1(ii) includes six requirements that are either addressed by Reliability Standards approved by the Commission or by Reliability Standards PER-006-1and PRC-027-1. Specifically, NERC explained that Reliability Standard PRC-001-1.1(ii), Requirement R1 has been partially replaced by Reliability Standards PER-003-1 and PER-005-2. NERC continued that Reliability Standard PER-006-1 and the revised definitions of operational planning analysis and  real-time assessment will replace the remaining portions of Reliability Standard PRC-001-1.1(ii), Requirement R1. NERC asserted that Reliability Standard PRC-001-1.1(ii), Requirement R2 has been addressed by Reliability Standards IRO-001-4, IRO-008-2, IRO-010-2, TOP-001-3, and TOP-003-3, which the Commission approved in Order  No. 817.[15]
                    
                     NERC stated that Reliability Standard PRC-027-1 will replace Reliability Standard PRC-001-1.1(ii), Requirements R3 and R4. NERC also explained that Reliability Standard PRC-001-1.1(ii), Requirement R5 has been replaced with several Reliability Standards developed after Reliability Standard PRC-001-1(ii) became effective.[16]
                    
                     NERC further stated that Reliability Standard PRC-001-1.1(ii), Requirement R6 has been replaced with Reliability Standards TOP-001-3 and TOP-003-3. D. Notice of Proposed Rulemaking 11. On November 16, 2017, the Commission issued a Notice of Proposed Rulemaking proposing to approve Reliability Standards PRC-027-1 and PER-006-1.[17]
                    
                     The NOPR proposed to determine that Reliability Standards PRC-027-1 and PER-006-1 improve upon the currently-effective Reliability Standards. However, the NOPR observed that Reliability Standard PRC-027-1, Requirement R2, Option 2 does not appear to ensure coordination of all bulk electric system elements with protection system functions because it does not require an initial protection system coordination study. Accordingly, the NOPR also proposed to direct NERC, pursuant to section 215(d)(5) of the FPA, to submit modifications to Reliability Standard PRC-027-1 within 12 months of the effective date of this Final Rule to require an initial protection system coordination study to ensure that applicable entities will perform (or have performed), as a baseline, a study demonstrating proper coordination of its protection systems.[18] 12. In addition, the NOPR proposed to approve the associated violation risk factors and violation severity levels, implementation plan, and effective date proposed by NERC.[19]
                    
                     The NOPR also proposed to approve the revised definitions for inclusion in the NERC 
                    ( print page 27507)
                    Glossary.[20]
                    
                     Further, the NOPR proposed to approve the retirement of Reliability Standard PRC-001-1.1(ii), as requested by NERC.[21] 13. In response to the NOPR, the Commission received fifteen sets of comments. We address below the issues raised in the NOPR and comments. The Appendix to this Final Rule lists the entities that filed comments in response to the NOPR. II. Discussion 14. Pursuant to section 215(d)(2) of the FPA, we approve Reliability Standards PER-006-1 and PRC-027-1 as just, reasonable, not unduly discriminatory or preferential, and in the public interest, as both Reliability Standards improve on currently-effective Reliability Standard PRC-001-1.1(ii) in important ways.[22]
                    
                     As discussed below, we do not adopt the NOPR proposal to direct NERC to modify Reliability Standard PRC-027-1 to require coordination of all bulk electric system elements with protection system functions. 15. Reliability Standard PRC-027-1 improves on currently-effective Reliability Standard PRC-001-1.1(ii) by: (1) Modifying the applicability section to include the appropriate functional entity types with the responsibilities, resources, and skill sets to conduct the studies required to coordinate protection systems, and (2) listing the protection system functions on all bulk electric system elements that require coordination. Reliability Standard PER-006-1, along with existing formal training requirements in the Personnel Performance, Training, and Qualifications (PER) group of Reliability Standards, also improves upon Reliability Standard PRC-001-1.1(ii), Requirement R1 by ensuring that the necessary personnel are familiar with and understand the purpose and limitations of protection systems schemes while providing more precise and auditable requirements. 16. In addition, we approve NERC's associated violation risk factors, violation severity levels, implementation plans, and effective dates. We also approve the revised definitions for inclusion in the NERC Glossary. Further, we approve the retirement of Reliability Standard PRC-001-1.1(ii), as requested by NERC. Initial Protection System Coordination Study NOPR 17. The NOPR proposed to direct that NERC develop modifications to Reliability Standard PRC-027-1 to ensure coordination of all bulk electric system elements with protection system functions by requiring that applicable entities perform an initial protection coordination study under Requirement R2, Option 2. Comments 18. NERC does not support the proposed directive because it believes that the proposed directive is unduly burdensome and unsupported by the materials cited in the NOPR. NERC contends that while the “proposed directive could potentially help reduce misoperations caused by coordination issues . . . [it] would also impose a significant burden on industry . . . requiring a substantial expenditure of resources.” [23]
                    
                     NERC also states that it “expects that many entities will choose to do a full Protection System Coordination Study . . . for their more impactful [bulk electric system] Elements” and that “it is highly likely that the overwhelming majority of entities have already conducted coordination studies for their Protection Systems.” [24]
                    
                     While NERC agrees with the goal of reducing protection system misoperation rates on the bulk electric system, it contends that recent misoperation rates demonstrate that mis-coordination of existing protection systems “does not present a widespread risk to [bulk electric system] reliability that would necessitate the expenditure of resources required to conduct full Protection System Coordination Studies for every [bulk electric system] element with a Protection System.” [25] 19. In addition, NERC and other commenters contend that the materials cited in the NOPR do not support the proposal to modify Reliability Standard PRC-027-1.[26]
                    
                     NERC, EEI and Tri-State contend that the Arizona Southern California September 8, 2011 Outage Report is unsupportive because it addresses mis-coordination of remedial action schemes and not protection systems.[27]
                    
                     NERC and Tri-State assert that the NERC System Protection Control Task Force Report addressed issues specific to generation transmission interfaces and did not apply broadly to all bulk electric system elements with protection systems.[28]
                    
                     NERC and Tri-State also contend that the 2009 letter from the NERC President to the NERC board of Trustees and stakeholders is no longer relevant because mis-coordination issues are now responsible for a smaller percentage of events and that mis-coordination has not recently caused any significant system disturbances.[29]
                    
                     NERC and Tri-State claim that Reliability Standard PRC-004 now requires applicable entities to mitigate the effects of misoperations by implementing a corrective action plan that has reduced misoperations.[30] 20. Further, while NERC agrees with the 2013 Misoperations Report that reducing misoperations, including mis-coordination events, is an important priority for bulk electric system reliability, NERC contends that the report does not indicate that requiring protection system coordination studies for all applicable elements, as proposed in the NOPR, is the only or optimal way to reduce mis-coordination events.[31]
                    
                     EEI also contends that the 2013 Misoperations Report shows that human error and lack of training are responsible for a significant portion of misoperations.[32] 21. NERC, EEI, and Tri-State explain that the 2014 incident identified in the “lessons learned” document on “Generation Relaying—Underfrequency Protection Coordination” was unrelated to protection system coordination.[33] 22. Finally, NERC states that while the 2016 State of Reliability Report highlights the continued need to reduce misoperations, the report does not indicate that there is a need to require entities to perform a protection system coordination study for every bulk electric system element with a protection system.[34]
                    
                     NERC also contends that the 2017 State of Reliability Report observes a continuing decline in misoperation rates, but that misoperations are a priority for NERC.[35]
                    
                     NERC states that the misoperations rate within the Texas Reliability Entity Region observed in the 2016 State of Reliability Report was mitigated by the 
                    ( print page 27508)
                    time NERC issued the 2017 State of Reliability Report.[36]
                    
                     NERC claims that this reduction in misoperation events is evidence that requiring entities to perform protection system coordination studies is unnecessary because the entities will address the misoperation events without specific requirements in Reliability Standards.[37] 23. Other commenters do not support the proposal to direct NERC to develop modifications to Reliability Standard PRC-027-1 because they generally contend that the proposed directive is not necessary and would impose a burden without a proportional reliability benefit.[38]
                    
                     Hydro One estimates that it will need approximately 30,000 hours of work to perform an initial protection system coordination study.[39]
                    
                     Tri-State estimates that it would take an engineer at least twenty hours to perform a protection system coordination study at each of its approximately 700 terminals.[40]
                    
                     Tri-State estimates that the actual cost to all applicable entities could be more than $120 million.[41]
                    
                     PG&E estimates a cost to industry “greatly in excess of $100 million” and asserts that the proposed directive would require PG&E to perform coordination studies for 95 percent of the PG&E bulk electric system at a cost of $3.5 million in engineering labor.[42] 24. Entergy requests that the Commission find that NERC's approach for requiring protection system coordination studies achieves the Reliability Standard's “reliability goals effectively and efficiently.” [43]
                    
                     Entergy opines that, by adopting NERC's proposal without modification, the Commission appropriately would give “due weight” to the technical expertise of the ERO. Entergy asserts that NERC properly supported Requirement R2 by setting forth evidence of the frequency of coordination events over a four-year period, which shows that only 11 percent of misoperation events (17 events out of 151) and only 2.9 percent of total events (17 out of 574) involved Protection System coordination issues. Further, Entergy claims that, in proposing the Reliability Standard, NERC was aware of the possibility that some bulk electric system elements may never undergo a Protection System Coordination Study and that “NERC does not afford this possibility the same risk as the Commission.” [44]
                    
                     According to Entergy, “NERC has properly balanced the implementation costs and reliability benefits of the proposed  PRC-027-1 Reliability Standard and determined that Option 2 is sufficient to ensure reliability” and the Commission should defer to NERC's expertise, or otherwise provide more support to justify a deviation from NERC's proposal. 25. In addition, some commenters expressed concern that applicable entities may not have maintained sufficient documentation to substantiate prior protection system coordination studies and, as result, entities would have to perform new protection system coordination studies purely for compliance purposes.[45] 26. As an alternative to the proposed directive, NERC and other commenters suggest that Reliability Standard PRC-027-1 be modified so that it requires an applicable entity to conduct an initial baseline protection system coordination study on a certain subset of its bulk electric system elements (
                    *i.e.,*
                     based on a higher voltage or higher risk protection systems).[46]
                    
                     NERC and other commenters also request that the Commission permit NERC to allow more than 6 years to complete the initial baseline protection system coordination studies (
                    *i.e.,*
                     10 or 12 years) if the Commission directs NERC to modify Reliability Standard PRC-027-1.[47]
                    
                     EEI recommends that if the Commission continues to have concerns about Reliability Standard PRC-027-1, Requirement R2, Option 2, as an alternative to the proposed directive, a final rule should direct NERC “to assess the effectiveness of Option 2 after the implementation of the proposed Reliability Standard and if necessary make technical recommendations to improve the efficiency and effectiveness as appropriate.” [48] 27. Idaho Power supports the proposed directive.[49]
                    
                     Idaho Power supports eliminating Reliability Standard PRC-027-1, Requirement R2, Option 2 because it contends that Option 1 is a more robust option explaining that it is “preferable because it is more likely to address miscoordinations.” [50] Commission Determination 28. Based on the record before us, we do not adopt the directive proposed in  the NOPR. The record in this proceeding supports the NOPR's conclusion that  mis-coordination of protection systems may pose a potential reliability risk and, as currently drafted, Reliability Standard PRC-027-1, Requirement R2, Option 2 permits applicable entities to forego protection system coordination studies under certain circumstances.[51]
                    
                     However, we are persuaded by the statements from NERC and other commenters that applicable entities generally perform, or will choose to perform for their significant facilities, protection system coordination studies even in the absence of a Reliability Standard requirement.[52]
                    
                     We also recognize the concern raised by commenters regarding the burden of compliance. Specifically, we recognize the concern that were the NOPR directive adopted, applicable entities could be required to re-run protection system coordination studies for the sole purpose of generating compliance documentation, even if such entities already performed protection 
                    ( print page 27509)
                    system coordination studies that remain valid but lack documentation to substantiate compliance. Accordingly, pursuant to 215(d)(2) of the FPA, we approve Reliability Standard PRC-027-1 and do not direct modifications to the Reliability Standard.[53] III.  Information Collection Statement 29. The collections of information addressed in this Final Rule are subject to review by the Office of Management and Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of 1995.[54]
                    
                     OMB's regulations require approval of certain information collection requirements imposed by agency rules.[55]
                    
                     Upon approval of a collection(s) of information, OMB will assign an OMB control number and an expiration date. Respondents subject to the filing requirements of a rule will not be penalized for failing to respond to these collections of information unless the collections of information display a valid OMB control number. 30. The Commission solicited public comments in the NOPR on the need for this information, whether the information will have practical utility, the accuracy of the burden estimates, ways to enhance the quality, utility, and clarity of the information to be collected or retained, and any suggested methods for minimizing respondents' burden, including the use of automated information techniques. The Commission did not receive comments regarding the burden estimates for the Reliability Standards approved herein (
                    *i.e.,*
                     Reliability Standards PRC-027-1 and PER-006-1).[56] 31. The information collection requirements in this Final Rule in Docket  No. RM16-22-000 are associated with FERC-725A, FERC-725G, and FERC-725Y,  as discussed below.[57] 32. 
                    *Public Reporting Burden:*
                     The number of respondents below is based on an examination of the NERC compliance registry on December 1, 2017, for transmission owners, generator owners, generator operators, and distribution providers within the United States and an estimate of how many such entities from that registry will be affected by the Reliability Standards in this Final Rule for adoption and implementation. As of December 1, 2017, 337 transmission owners, 971 generator owners, 944 generator operators, and 419 distribution providers in the United States were registered in the NERC compliance registry. However, under NERC's compliance registration program, entities may be registered for multiple functions, so these numbers incorporate some double counting. We note that many generation sites share a common generator owner or generator operator. The following table provides the estimated annual burden and cost related to information collection requirements in this Final Rule.[58] Changes Due to the Final Rule in Docket No. RM16-22-000
Respondent category and requirement 59
Number of 
                             respondents
Annual 
                             number of  
                             responses per  
                             respondent
Total 
                             number of  
                             annual  
                             responses
Average burden hours and cost per response 60
Annual burden hours and total annual cost 
                             
                                (rounded) 61(1)
(2)
(1) * (2) = (3)
(4)
(3) * (4) = (5)**FERC-725G (Reliability Standard PRC-027-1)**
                             62TO; Reporting Reqs. R1, R2, & R3
337
1
337
60 hrs.; $3,941.40
20,220 hrs.; $1,328,252.TO; Recordkeeping Reqs
337
1
337
40 hrs.; $1,565.60
13,480 hrs.; $527,607.GO; Reporting Reqs. R1, R2, & R3
971
1
971
10 hrs.; $656.90
9,710 hrs.; $637,830.GO; Recordkeeping Reqs
971
1
971
10 hrs.; $391.40
9,710 hrs.; $380,049.DP; Reporting Reqs. R1, R2, & R3
419
1
419
10 hrs.; $656.90
4,190 hrs.; $275,241.DP; Recordkeeping Reqs
419
1
419
10 hrs.; $391.40
4,190 hrs.; $163,997.*Sub-Total for Reporting Reqs. for FERC-725G*




34,120 hrs.; $2,241,323.*Sub-Total for Recordkeeping Reqs. for FERC-725G*




27,380 hrs.; $1,072,653.Total Increase for FERC-725G




61,500 hrs.; $3,313,976.**FERC-725Y (Reliability Standard PER-006-1)**
                             63GOP; Reporting Req. R1
944
1
944
5 hrs.; $328.45
4,720 hrs.; $310,057.GOP; Recordkeeping Req
944
1
944
10 hrs.; $391.40
9,440 hrs.; $369,482.Total Increase for FERC-725Y




14,160 hrs.; $679,539.**Reductions to FERC-725A (retirement of Reliability Standard PRC-001-1.1)**
                             64GOP; Reporting Req
944
1
944
40 hrs.; $2,627.60
37,760 hrs.; $2,480,454.GOP; Recordkeeping Req
944
1
944
50 hrs.; $1,957.00
47,200 hrs.; $1,847,408.TOP; Reporting Req
176
1
176
60 hrs.; $3,941.40
10,560 hrs.; $693,686.TOP; Recordkeeping Req
176
1
176
70 hrs.; $2,739.80
12,320 hrs.; $482,205.BA; Reporting Req
99
1
99
32 hrs.; $2,102.08
3,168 hrs.; $208,106.BA; Recordkeeping Req
99
1
99
20 hrs.; $782.80
1,980 hrs.; $77,497.*Reduction Sub-Total Reporting Reqs. for FERC-725A*




51,484 hrs.; $3,382,246.*Reduction Sub-Total Recordkeeping Reqs. for FERC-725A*




61,500 hrs.; $2,407,110.Reduction Sub-Total for FERC-725A




112,984 hrs.; $5,789,356 (reduction).( print page 27510)NET TOTAL REDUCTION FOR CHANGES IN RM16-22-000




37,324 hrs.; $1,795,841 (reduction).
 *Titles:*
                     FERC-725A
                    
                     (Mandatory Reliability Standards for the Bulk-Power System), FERC-725G (Reliability Standards for the Bulk Power System: PRC Reliability Standards) and FERC-725Y (Mandatory Reliability Standards: Operations Personnel Training). *Action:*
                     Revisions
                    
                     to existing collections. *OMB Control Nos.:*
                     1902-0244
                    
                     (FERC-725A); 1902-0252 (FERC-725G) and 1902-0279 (FERC-725Y). *Respondents:*
                     Business or
                    
                     other for profit, and not for profit institutions. *Frequency of Responses:*
                     Annual
                    
                     recordkeeping and reporting requirements, with some reporting requirements being at least once every six years. *Necessity of the Information:*
                     Reliability Standards PRC-027-1 and PER-006-1 set forth requirements for coordination of protection systems and personnel training on specific topics essential to reliability. The Commission approves Reliability Standards PRC-027-1 and PER-006-1, which will replace Commission-approved Reliability Standard PRC-001-1.1(ii). Reliability Standards PRC-027-1 and PER-006-1 improve upon existing Reliability Standard PRC-001-1.1(ii) because the Reliability Standards assign responsibilities to entities with more appropriate resources and skill sets to conduct studies required to coordinate protection systems. The approved Reliability Standards also provide additional clarity to applicable entities. *Internal review:*
                     The Commission has assured itself, by means of its internal review, that there is specific, objective support for the burden estimates associated with the information requirements. IV.  Environmental Analysis 33. The Commission is required to prepare an Environmental Assessment or an Environmental Impact Statement for any action that may have a significant adverse effect on the human environment.[65]
                    
                     The action here falls within the categorical exclusion in the Commission's regulations for rules that are clarifying, corrective or procedural, for information gathering, analysis, and dissemination.[66] V.  Regulatory Flexibility Act 34. The Regulatory Flexibility Act of 1980 (RFA) generally requires a description and analysis of final rules that will have significant economic impact on a substantial number of small entities.[67]
                    
                     The Small Business Administration (SBA) defines which utilities are small businesses based on the number of employees that a utility and its affiliates employ.[68] 35. Reliability Standard PRC-027-1 (included in FERC-725G) will apply to approximately 1,727 entities (337 transmission owners, 971 generator owners, and  419 distribution providers) in the United States.[69]
                    
                     Pursuant to SBA regulations, the small business threshold for Electric Bulk Power Transmission and Control is 500 employees. For generator owners, the small generator threshold ranges from 250 to 750 employees (depending on the fuel source). For Electric Power Distribution, the small business threshold is 1,000 employees. We estimate that the annual cost for each entity will be $1,048 for each generator owner and distribution provider and $5,507 for each transmission owner. 36. Reliability Standard PER-006-1 (included in FERC-725Y) will apply to approximately 944 generator operators in the United States. Pursuant to SBA regulations the small business threshold for generator operators ranges from 250 to 750 employees (depending on the fuel source). We estimate that the annual cost for each generator operator will be $719. 37. The retirement of Reliability Standard PRC-001-1.1(ii) (included in FERC-725A) will decrease the annual estimated cost for 944 generator operators by $4,585 each, for 176 transmission operators by $6,681 each, and for 99 balancing authorities by $2,885 each. For the generator operators affected by this retirement and approval of Reliability Standard PER-006-1, the net annual effect would be a decrease of $3,866 each. 38. We estimate the net annual cost of this Final Rule would vary, by type of entity, from an annual decrease of $6,681 (for each transmission operator) to an annual increase of $5,507 (for each transmission owner). We view this as a minimal economic impact for each entity. Accordingly, we certify that this Final Rule will not have a significant economic impact on a substantial number of small entities. VI.  Document Availability 39. In addition to publishing the full text of this document in the 
                    **Federal 
                        ( print page 27511)
                        Register**
                    , the Commission provides all interested persons an opportunity to view and/or print the contents of this document via the internet through FERC's Home Page (
                    *http://www.ferc.gov*) and in FERC's Public Reference Room during normal business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE, Room 2A, Washington, DC 20426. 40. From FERC's Home Page on the internet, this information is available on eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft Word format for viewing, printing, and/or downloading. To access this document in eLibrary, type the docket number excluding the last three digits of this document in the docket number field. 41. User assistance is available for eLibrary and the FERC's website during normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) or email at 
                    *ferconlinesupport@ferc.gov,*
                     or the Public Reference Room at 202-502-8371, TTY 202-502-8659. Email the Public Reference Room at 
                    *public.referenceroom@ferc.gov.* VII.  Effective Date and Congressional Notification 42. The Final Rule is effective August 13, 2018. The Commission has determined, with the concurrence of the Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule is not a “major rule” as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 1996. This Final Rule is being submitted to the Senate, House, and Government Accountability Office. By the Commission. Issued: June 7, 2018. Nathaniel J. Davis, Sr., Deputy Secretary.
 Note: The following appendix will not appear in the Code of Federal Regulations. Appendix List of Commenters APPA/TAPS
American Public Power
                                 Association and Transmission 
                                 Access Policy Study GroupEEI
Edison Electric Institute.El Paso Electric
El Paso Electric Company.Entergy
Entergy Services, Inc.Hydro One
Hydro One Networks Inc.Idaho Power
Idaho Power Company.ITC
International Transmission Company d/b/a ITC Transmission, Michigan Electric Transmission Company, LLC, ITC Midwest LLC and ITC Great Plains, LLC.LPPC
Large Public Power Council.NPPD
Nebraska Public Power District.NERC
North American Electric Reliability Corporation.NRECA/ELCON
National Rural Electric Cooperative Association and the Electricity Consumers Resource Council.Oncor
Oncor Electric Delivery.PG&E
Pacific Gas and Electric Company.SCE&G
South Carolina Electric and Gas Company.Tri-State
Tri-State Generation and Transmission Association, Inc.


# Footnotes

1.
    
                         16 U.S.C. 824o (2012). Back to Citation
 2.
    
                         NERC Glossary of Terms Used in NERC Reliability Standards (NERC Glossary). Back to Citation
 3.
    
                         
                        *Id.*
                         824o(c), (d). Back to Citation
 4.
    
                         
                        *Id.*
                         824o(e). Back to Citation
 5.
    
                         
                        *North American Electric Reliability Corp.,*
                         116 FERC ¶ 61,062, 
                        *order on reh'g and compliance,*
                         117 FERC ¶ 61,126 (2006), 
                        *order on compliance,*
                         118 FERC ¶ 61,190, 
                        *order on reh'g,*
                         119 FERC ¶ 61,046 (2007), 
                        *aff'd sub nom. Alcoa Inc.*
                         v. 
                        *FERC,*
                         564 F.3d 1342 (D.C. Cir. 2009). Back to Citation
 6.
    
                         
                        *Mandatory Reliability Standards for the Bulk-Power System,*
                         Order No. 693, FERC Stats. & Regs. ¶ 31,242 at PP 1433-1449, 
                        *order on reh'g,*
                         Order No. 693-A, 120 FERC ¶ 61,053 (2007). Back to Citation
 7.
    
                             Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1449. Back to Citation
 8.
    
                         Reliability Standards PRC-027-1 and PER-006-1 are not attached to this Final Rule. The Reliability Standards are available on the Commission's eLibrary document retrieval system in Docket No. RM16-22-000 and are posted on the NERC website, 
                        *http://www.nerc.com.* Back to Citation
 9.
    
                         NERC Petition at 10. Back to Citation
 10.
    
                         
                        *Id.*
                         at 13. Back to Citation
 11.
    
                         
                        *Id.*
                         at 15. Back to Citation
 12.
    
                             
                            *Id.*
                             at 26. Back to Citation
 13.
    
                         
                        *Id.*
                         at 27. Back to Citation
 14.
    
                         
                        *Id.*
                         at 26. Back to Citation
 15.
    
                         
                        *Id.*
                         at 5 (citing 
                        *Transmission Operations Reliability Standards and Interconnection Reliability Operations and Coordination Reliability Standards,*
                         Order No. 817, 153 FERC ¶ 61,178 (2015)). Back to Citation
 16.
    
                         
                        *Id.*
                         at 6. Back to Citation
 17.
    
                         
                        *Coordination of Protection Systems for Performance During Faults and Specific Training for Personnel Reliability Standards,*
                         Notice of Proposed Rulemaking, 82 FR 55535 (Nov. 22, 2017), 161 FERC ¶ 61,159, at P 12 (2017) (NOPR). The NOPR was erroneously published a second time in the 
                        **Federal Register**
                         on November 28, 2017, which changed the comment date to January 29, 2018. 82 FR 56759 (Nov. 30, 2017);  82 FR 56186 (Nov. 28, 2017). Back to Citation
 18.
    
                         NOPR, 161 FERC ¶ 61,159 at PP 14, 24. Back to Citation
 19.
    
                         
                        *Id.*
                         P 13. Back to Citation
 20.
    
                         
                        *Id.* Back to Citation
 21.
    
                         
                        *Id.* Back to Citation
 22.
    
                         16 U.S.C. 824o(d)(2). Back to Citation
 23.
    
                         NERC Comments at 4. Back to Citation
 24.
    
                         
                        *Id.*
                         at 5-6. Back to Citation
 25.
    
                         
                        *Id.*
                         at 6. Back to Citation
 26.
    
                         
                        *See generally*
                         NERC Comments; EEI Comments; Tri-State Comments; Entergy Comments; ITC Comments. Back to Citation
 27.
    
                         NERC Comments at 7; EEI Comments at 7; Tri-State Comments at 7-8. Back to Citation
 28.
    
                         NERC Comments at 7-8; Tri-State Comments at 8-9. Back to Citation
 29.
    
                         NERC Comments at 8; Tri-State Comments at 9-10. Back to Citation
 30.
    
                         NERC Comments at 8; Tri-State Comments at 9. Back to Citation
 31.
    
                         NERC Comments at 9. Back to Citation
 32.
    
                         EEI Comments at 7. Back to Citation
 33.
    
                         NERC Comments at 10; EEI Comments at 8; Tri-State Comments at 10. Back to Citation
 34.
    
                         NERC Comments at 10. Back to Citation
 35.
    
                         
                        *Id.*
                         at 9. Back to Citation
 36.
    
                         NERC Comments at 11; 
                        *see also*
                         Entergy Comments at 8. Back to Citation
 37.
    
                         NERC Comments at 11. Back to Citation
 38.
    
                         APPA/TAPS Comments at 3; EEI Comments at 3; El Paso Electric Comments at 4; Entergy Comments at 4; Hydro One Comments at 1-2; ITC Comments at 3; LPPC Comments at 2; NPPD Comments at 1; NRECA/ELCON Comments at 5; Oncor Comments at 1; PG&E Comments at 2; SCE&G Comments at 1; Tri-State Comments  at 4. Back to Citation
 39.
    
                         Hydro One Comments at 1. Back to Citation
 40.
    
                         
                        *Id.*
                         at 13. Back to Citation
 41.
    
                         
                        *Id.* Back to Citation
 42.
    
                         PG&E Comments at 3. Back to Citation
 43.
    
                         Entergy Comments at 5. Back to Citation
 44.
    
                         
                        *Id.*
                         at 9-10. Back to Citation
 45.
    
                         ITC Comments at 4; Entergy Comments at 1; NPPD Comments at 1; PG&E Comments at 3. Back to Citation
 46.
    
                         NERC Comments at 11-12; El Paso Electric Comments at 2; Entergy Comments at 12; NRECA/ELCON Comments at 6-7. Back to Citation
 47.
    
                         NERC Comments at 12; El Paso Electric Comments at 2-3; Entergy Comments at 12-13; NRECA/ELCON Comments at 6-7. Separately, El Paso Electric contends that the six-year cycle proposed by NERC in Reliability Standard PRC-027-1, Requirement R2 is too short and directs resources away from “other activities that have a greater likelihood of improving reliability outcomes in a demonstrable way.” El Paso Electric Comments at 2. We disagree. NERC recognized the potential burden imposed by Requirement R2 and determined that six years “balance[d] the resources required to perform Protection System Coordination Studies and the potential reliability impacts created by incremental changes of Fault current over time.” NERC Petition at 40. Moreover, during the standard drafting process, some commenters indicated that  six years was too long an interval. 
                        *See, e.g.,*
                         NERC Petition, Exhibit G (Summary of Development History and Record of Development) at 1479 of pdf (ReliabilityFirst recommending a 24-month period to conduct protection system coordination study),  2169 of pdf (Texas RE stating that six years is too long of a time period between studies of fault currents). Back to Citation
 48.
    
                         EEI Comments at 6. Back to Citation
 49.
    
                         Idaho Power Comments at 1-2. Back to Citation
 50.
    
                         
                        *Id.*
                         at 2. Back to Citation
 51.
    
                         
                        *See, e.g.,*
                         NERC Comments at 6 (“NERC and the standard drafting team concluded that Protection System coordination did not present a prevalent enough risk to the reliable operation of the [bulk electric system] to warrant imposing the burden of requiring applicable entities to perform a full Protection System Coordination Study for every [bulk electric system] Element with a Protection System.”); Entergy Comments  at 9 (“In proposing the Reliability Standard, NERC was aware of the possibility that some bulk electric system elements may never undergo a Protection System Coordination Study.”). Back to Citation
 52.
    
                         
                        *See, e.g.,*
                         NERC Comments at 5; NPPD Comments at 1; Tri-State Comments  at 10; ITC Comments at 4. Back to Citation
 53.
    
                         16 U.S.C. 824o(d)(2). Back to Citation
 54.
    
                         44 U.S.C. 3507(d) (2012). Back to Citation
 55.
    
                         5 CFR 1320.11 (2017). Back to Citation
 56.
    
                         As discussed above, several commenters addressed the potential burden of a new version of Reliability Standard PRC-027-1 modified, pursuant to the Commission's directive, to require initial protection system coordination studies. 
                        *See, e.g.,*
                         Tri-State Comments at 12. However, those comments are not relevant to the burden estimates contained in this Final Rule because, herein, the Commission only approves Reliability Standards PRC-027-1 and PER-006-1. Back to Citation
 57.
    
                         In the NOPR in Docket No. RM16-22-000, some of the reporting requirements were included under FERC-725G6 (OMB Control No. 1902-0300), a temporary place holder, because FERC-725G was pending review at OMB in an unrelated action. As indicated below, those reporting requirements are now included under FERC-725G (OMB Control No. 1902-0252). When the NOPR in Docket No. RM16-22-000 was issued, another unrelated item affecting FERC-725A was pending OMB review. Burden estimates were provided in order to solicit public comments, but the burden reduction  to FERC-725A was not submitted to OMB at that time. The burden reduction to  FERC-725A for this Final Rule will be submitted to OMB for review. Back to Citation
 58.
    
                         TO = transmission owner; TOP = transmission operator; GO = generator owner; GOP = generator operator; DP = distribution provider; and BA = balancing authority. Back to Citation
 59.
    
                         For each Reliability Standard, the Measure shows the acceptable evidence for the associated Reporting Requirement, and the Compliance section details the related Recordkeeping Requirement. 60.
    
                         The estimates for cost per hour are based on May 2016 wage figures from the Bureau of Labor Statistics (BLS, 
                        *https://www.bls.gov/​oes/​current/​naics2_​22.htm*)  and BLS benefits information from March 20, 2018 (for December 2017, 
                        *https://www.bls.gov/​news.release/​ecec.nr0.htm*). The estimated hourly cost, for wages plus benefits, are: (a) $68.12/hour, for electrical engineer, Occupation Code 17-2071, and (b) $39.14/hour, for information and record clerk, Occupation Code 43-4199. The hourly cost for an electrical engineer is used for the reporting requirements; the hourly cost for a record clerk is used for the recordkeeping requirements. Back to Citation
 61.
    
                         For display purposes, the cost figures in column 5 have been rounded. Back to Citation
 62.
    
                         Some of the reporting requirements are required at least every six calendar years. In this table, the Commission assumes that respondents might work on some of their elements each year; the annual burden estimate shown is one sixth of the burden associated with one complete six-year cycle. For example, for each transmission owner:  (a) The annual reporting burden associated with Requirements R1, R2, and R3 is shown as 60 hours per year, and (b) the burden for the six-year cycle would be six times that, or a total of 360 hours. Back to Citation
 63.
    
                         In order to provide improved information on the Reliability Standard and associated burden, FERC-725Y (rather than FERC-725A) will cover the burden required by PER-006-1. Back to Citation
 64.
    
                         The estimates for average annual burden hours per response are based on figures in Order No. 693. Order No. 693, FERC Stats. & Regs. ¶ 31,242, at PP 1906-1907. The numbers of respondents and estimated hourly costs are based on current figures. Back to Citation
 65.
    
                         
                        *Regulations Implementing the National Environmental Policy Act of 1969,*
                         Order No. 486, FERC Stats. & Regs. ¶ 30,783 (1987) (cross-referenced at 41 FERC ¶ 61,284). Back to Citation
 66.
    
                         18 CFR 380.4(a)(2)(ii) (2017). Back to Citation
 67.
    
                         5 U.S.C. 601-612 (2012). Back to Citation
 68.
    
                         13 CFR 121.201, Subsector 221 (2017). Back to Citation
 69.
    
                         Many respondents serve multiple roles in the NERC compliance registry, so there is likely double counting in the estimates. Back to Citation


[FR Doc. 2018-12663 Filed 6-12-18; 8:45 am] BILLING CODE 6717-01-P