This section of the FEDERAL REGISTER

contains regulatory documents having general

applicability and legal effect, most of which

are keyed to and codified in the Code of

Federal Regulations, which is published under

50 titles pursuant to 44 U.S.C. 1510.

The Code of Federal Regulations is sold by

the Superintendent of Documents.

Rules and Regulations Federal Register

27505 

Vol. 83, No. 114 

Wednesday, June 13, 2018 

1 16 U.S.C. 824o (2012). 

2NERC Glossary of Terms Used in NERC 

Reliability Standards (NERC Glossary). 

3 Id. 824o(c), (d). 

4 Id. 824o(e). 

5North 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). 

6 Mandatory Reliability Standards for the BulkPower 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). 

7Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 1449. 

8Reliability 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. 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket No. RM16–22–000; Order No. 847] 

Coordination of Protection Systems for 

Performance During Faults and 

Specific Training for Personnel 

Reliability Standards 

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 Commissioncertified 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


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9NERC Petition at 10. 

10 Id. at 13. 

11 Id. at 15. 

12 Id. at 26. 

13 Id. at 27. 

14 Id. at 26. 

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)). 

16 Id. at 6. 

17Coordination 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). 

18NOPR, 161 FERC ¶ 61,159 at PP 14, 24. 

19 Id. P 13. 

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 currentlyeffective 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 realtime 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 


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20 Id. 

21 Id. 

22 16 U.S.C. 824o(d)(2). 

23NERC Comments at 4. 

24 Id. at 5–6. 

25 Id. at 6. 

26See generally NERC Comments; EEI Comments; 

Tri-State Comments; Entergy Comments; ITC 

Comments. 

27NERC Comments at 7; EEI Comments at 7; TriState Comments at 7–8. 

28NERC Comments at 7–8; Tri-State Comments at 

8–9. 

29NERC Comments at 8; Tri-State Comments at 

9–10. 

30NERC Comments at 8; Tri-State Comments at 9. 

31NERC Comments at 9. 

32EEI Comments at 7. 

33NERC Comments at 10; EEI Comments at 8; TriState Comments at 10. 

34NERC Comments at 10. 

35 Id. at 9. 

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 currentlyeffective 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 miscoordination 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 miscoordination 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 


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36NERC Comments at 11; see also Entergy 

Comments at 8. 

37NERC Comments at 11. 

38APPA/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. 

39Hydro One Comments at 1. 

40 Id. at 13. 

41 Id. 

42PG&E Comments at 3. 

43Entergy Comments at 5. 

44 Id. at 9–10. 45 ITC Comments at 4; Entergy Comments at 1; 

NPPD Comments at 1; PG&E Comments at 3. 46NERC Comments at 11–12; El Paso Electric 

Comments at 2; Entergy Comments at 12; NRECA/ 

ELCON Comments at 6–7. 47NERC 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). 

48EEI Comments at 6. 

49 Idaho Power Comments at 1–2. 

50 Id. at 2. 

51See, 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.’’). 

52See, e.g., NERC Comments at 5; NPPD 

Comments at 1; Tri-State Comments at 10; ITC 

Comments at 4. 

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 


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Federal Register / Vol. 83, No. 114 / Wednesday, June 13, 2018 / Rules and Regulations 27509 

53 16 U.S.C. 824o(d)(2). 54 44 U.S.C. 3507(d) (2012). 55 5 CFR 1320.11 (2017). 56As 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. 

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. 

58TO = transmission owner; TOP = transmission 

operator; GO = generator owner; GOP = generator 

operator; DP = distribution provider; and BA = 

balancing authority. 

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) 62

TO; 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) 63

GOP; 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) 64

GOP; 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). 


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27510 Federal Register / Vol. 83, No. 114 / Wednesday, June 13, 2018 / Rules and Regulations 

59For each Reliability Standard, the Measure 

shows the acceptable evidence for the associated 

Reporting Requirement, and the Compliance section 

details the related Recordkeeping Requirement. 

60The 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. 

61For display purposes, the cost figures in 

column 5 have been rounded. 

62Some 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. 

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. 

64The 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. 

65Regulations Implementing the National 

Environmental Policy Act of 1969, Order No. 486, 

FERC Stats. & Regs. ¶ 30,783 (1987) (crossreferenced at 41 FERC ¶ 61,284). 

66 18 CFR 380.4(a)(2)(ii) (2017). 

67 5 U.S.C. 601–612 (2012). 

68 13 CFR 121.201, Subsector 221 (2017). 

69Many respondents serve multiple roles in the 

NERC compliance registry, so there is likely double 

counting in the estimates. 

CHANGES DUE TO THE FINAL RULE IN DOCKET NO. RM16–22–000—Continued 

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) 

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 


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Federal Register / Vol. 83, No. 114 / Wednesday, June 13, 2018 / Rules and Regulations 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 Group 

EEI ............... 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. 

APPA/TAPS 

American Public Power 

Association and Transmission 

Access Policy Study Group 

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. 

[FR Doc. 2018–12663 Filed 6–12–18; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF HOMELAND 

SECURITY 

Coast Guard 

33 CFR Part 165 

[Docket No. USCG–2018–0445] 

Safety Zone; Wendell Family Fourth of 

July Fireworks Display, Rockport, TX 

AGENCY: Coast Guard, DHS. 

ACTION: Notice of enforcement of 

regulation. 

SUMMARY: The Coast Guard will enforce 

the safety zone for the Wendell Family 

Fourth of July Fireworks Display on July 

4, 2018, to provide for the safety of life 

on navigable waterways during this 

event. Our regulation for marine events 

within the Eighth Coast Guard District 

identifies the regulated area for this 

event in Rockport, TX. During the 

enforcement periods, entry into these 

zones is prohibited unless authorized by 

the Captain of the Port Sector Corpus 

Christi (COTP) or a designated 

representative. 

DATES: The regulations in 33 CFR 

165.801, Table 4, Line 7 will be 

enforced from 8 p.m. through 9:30 p.m. 

on July 4, 2018. 

FOR FURTHER INFORMATION CONTACT: If 

you have questions about this notice of 

enforcement, call or email Petty Officer 

Kevin Kyles, Sector Corpus Christi 

Waterways Management Division, U.S. 

Coast Guard; telephone 361–939–5125, 

email Kevin.L.Kyles@uscg.mil. 

SUPPLEMENTARY INFORMATION: The Coast 

Guard will enforce the safety zone in 33 

CFR 165.801, Table 4, Line 7, for the 

Wendell Family Fourth of July 

Fireworks Display regulated area from 8 

p.m. through 9:30 p.m. on July 4, 2018. 

This action is being taken to provide for 

the safety of life on navigable waterways 

during this event. Our regulation for 

marine events within the Eighth Coast 

Guard District, § 165.801, specifies the 

location of the regulated area for the 

Wendell Family Fourth of July 

Fireworks which encompasses portions 

of Little Bay and Rockport Beach Park. 

As reflected in §§ 165.23 and 165.801(a), 

if you are the operator of a vessel in the 

regulated area you must comply with 

directions from the Captain of the Port 

Sector Corpus Christi (COTP) or a 

designated representative. Persons or 

vessels desiring to enter the zones must 

request permission from the COTP or a 

designated representative. They can be 

reached on VHF FM channel 16 or by 

telephone at (361) 939–0450. If 

permission is granted, all persons and 

vessels shall comply with the 

instructions of the COTP or designated 

representative. In addition to this notice 

of enforcement in the Federal Register, 

the COTP or a designated representative 

will inform the public through 

Broadcast Notice to Mariners (BNM), 

Local Notices to Mariners (LNM), 

Marine Safety Information Broadcasts 

(MSIBs), and/or through other means of 

public notice as appropriate at least 24 

hours in advance of each enforcement. 

Dated: June 6, 2018. 

E.J. Gaynor, 

Captain, U.S. Coast Guard, Captain of the 

Port Sector Corpus Christi. 

[FR Doc. 2018–12645 Filed 6–12–18; 8:45 am] 

BILLING CODE 9110–04–P 

DEPARTMENT OF HOMELAND 

SECURITY 

Coast Guard 

33 CFR Part 165 

[Docket Number USCG–2018–0535] 

RIN 1625–AA00 

Safety Zone; Lewis River, Ridgefield, 

WA 

AGENCY: Coast Guard, DHS. 

ACTION: Temporary final rule. 

SUMMARY: The Coast Guard is 

establishing a temporary safety zone for 

navigable waters of the Lewis River near 

Ridgefield, WA. This action is necessary 


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