Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 16277 

103Order No. 743, 133 FERC ¶ 61,150 at P 169. 

104This analysis will determine if an Initial 

Regulatory Flexibility Analysis is required or if the 

Commission can certify that the revised definition 

will not have a significant economic impact on a 

substantial number of small companies. 

developed by NERC and approved by 

the Commission. 

107. TANC requests clarification that 

the Commission has not yet finalized its 

Regulatory Flexibility Act analysis and 

will not do so until NERC has submitted 

a proposed exemption process. 

108. Public Power Council, NYPSC 

and Snohomish argue that 

implementing the 100-kV threshold will 

be enormously costly. Public Power 

Council, for its part, argues that the 

Commission’s rejection of evidence of 

such increased compliance costs was 

arbitrary and capricious since, inter alia, 

Public Power Council did provide 

specific assertions as to how the Final 

Rule will have a significant economic 

impact on small entities. The NYPSC 

requests rehearing on whether the 

Commission’s decision to direct NERC 

to revise the bulk electric system 

definition to include facilities operated 

at 100 kV and above where the 

Commission failed to determine 

sufficient benefits in relation to the 

costs, resulting in the imposition of 

unnecessary costs without reliability 

benefits, was arbitrary, capricious, and 

an abuse of discretion. Snohomish states 

that it and many other entities operating 

in the Western Interconnection 

provided evidence demonstrating that 

imposition of the 100-kV threshold in 

the Western Interconnection will result 

of enormous compliance costs with no 

benefit to reliability since the 115-kV 

systems operated by these entities 

generally are used only for local 

distribution and their operation 

therefore has little or no effect on the 

interconnected bulk system. 

Commission Determination 

109. The Commission does not agree 

with commenters that its Regulatory 

Flexibility Act analysis was deficient, 

and we continue to believe that our 

suggested approach in Order No. 743 

will not have a significant economic 

impact on a substantial number of small 

entities.103 With respect to comments 

that we did not adequately consider the 

costs of implementing a 100 kV 

threshold, we note that the current bulk 

electric system definition contains a 

general 100 kV threshold. Thus, the 

burden of our suggested proposal to 

eliminate the regional discretion in the 

current definition and maintain a brightline 100 kV threshold should be 

minimal in all regions except NPCC. 

Even within the U.S. portion of the 

NPCC region, the Commission estimated 

in the Final Rule that only four of the 

33 transmission owners, transmission 

operators and transmission service 

providers may fall within the definition 

of small entities. We also believe that 

the exemption process will further 

ensure that the Final Rule minimally 

affects small entities. Finally, we have 

clarified on rehearing that NERC may 

develop criteria to identify local 

distribution facilities and certain 

categories of radial facilities that qualify 

for exclusion from the definition of the 

bulk electric system and therefore do 

not need to apply for exemption. For 

these reasons the Commission rejects 

the comments objecting to the 

Commission’s determinations regarding 

the cost of implementing a 100 kV 

threshold. 

110. However, the Commission will 

grant APPA’s and NRECA’s request for 

clarification in part. The Commission 

clarifies that it will perform a new 

Regulatory Flexibility Act analysis to 

determine whether the revised bulk 

electric system definition will have a 

significant economic impact on small 

entities when NERC submits its 

proposed definition, criteria for 

exclusion and the exemption process.104

We believe that the revisions NERC will 

propose will be sufficiently different 

from the initial NOPR proposal to 

warrant additional review to ensure that 

small entities are not unduly burdened. 

III. Document Availability 

111. In addition to publishing the full 

text of this document in the Federal 

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 p.m. Eastern time) at 888 First 

Street, NE., Room 2A, Washington, DC 

20426. 

112. 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. 

113. User assistance is available for 

eLibrary and the FERC’s Web site during 

normal business hours from FERC 

Online Support at 202–502–6652 (toll 

free at 1–866–208–3676) or e-mail at 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. E-mail the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

[FR Doc. 2011–6779 Filed 3–22–11; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket No. RM10–16–000; Order No. 749] 

System Restoration Reliability 

Standards 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: Under section 215 of the 

Federal Power Act, the Commission 

approves three Emergency Operations 

and Preparedness (EOP) Reliability 

Standards, EOP–001–1 (Emergency 

Operations Planning), EOP–005–2 

(System Restoration from Blackstart 

Resources), and EOP–006–2 (System 

Restoration Coordination) as well as the 

definition of the term ‘‘Blackstart 

Resource’’ submitted to the Commission 

for approval by the North American 

Electric Reliability Corporation (NERC), 

the Electric Reliability Organization 

certified by the Commission. The 

approved Reliability Standards require 

transmission operators, generation 

operators, and certain transmission 

owners and distribution providers to 

ensure that plans, facilities and 

personnel are prepared to enable system 

restoration from Blackstart Resources 

and require reliability coordinators to 

establish plans and prepare personnel to 

enable effective coordination of the 

system restoration process. The 

Commission also approves the NERC’s 

proposal to retire four existing EOP 

Reliability Standards and a definition 

that are replaced by the Standards and 

definition approved in this Final Rule. 

DATES: Effective Date: This rule will 

become effective May 23, 2011. 

FOR FURTHER INFORMATION CONTACT: 

Terence Burke (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–6498. 

David O’Connor (Technical 

Information), Office of Electric 

Reliability, Division of Reliability 

Standards, Federal Energy Regulatory 


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16278 Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 

1 16 U.S.C. 824o. 

2 Mandatory Reliability Standards for the BulkPower System, Order No. 693, 72 FR 16416 (Apr. 

4, 2007), FERC Stats. & Regs. ¶ 31,242, at P 297, 

order on reh’g, Order No. 693–A, 120 FERC ¶ 

61,053 (2007). 

3 Id. P 304–1899. 4 Id. P 542–676. 

5 Id. P 644. 

6 Id. P 630. 

7 Id. P 628. 

8 Id. P 638. 

9 Id. P 297, 644. 

10 Id. P 642–643, 647. 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502– 

6695. 

SUPPLEMENTARY INFORMATION: 

Before Commissioners: Jon Wellinghoff, 

Chairman; Marc Spitzer, Philip D. Moeller, 

John R. Norris, and Cheryl A. LaFleur. 

Final Rule 

Issued March 17, 2011. 

1. Under section 215 of the Federal 

Power Act (FPA),1 the Commission 

approves three Emergency Operations 

and Preparedness (EOP) Reliability 

Standards, EOP–001–1 (Emergency 

Operations Planning), EOP–005–2 

(System Restoration from Blackstart 

Resources), and EOP–006–2 (System 

Restoration Coordination) as well as the 

definition of the term ‘‘Blackstart 

Resource’’ submitted to the Commission 

for approval by the North American 

Electric Reliability Corporation (NERC), 

the Electric Reliability Organization 

(ERO) certified by the Commission. The 

approved Reliability Standards require 

transmission operators, generation 

operators, and certain transmission 

owners and distribution providers to 

ensure that plans, facilities, and 

personnel are prepared to enable system 

restoration from Blackstart Resources 

and require reliability coordinators to 

establish plans and prepare personnel to 

enable effective coordination of the 

system restoration process. The 

Commission also approves NERC’s 

proposal to retire four existing EOP 

Reliability Standards and the defined 

term ‘‘Blackstart Capability Plan’’ 

concurrent with the effectiveness of the 

Standards and the term Blackstart 

Resource approved in this Final Rule. In 

those jurisdictions where regulatory 

approval is required, Reliability 

Standard EOP–001–1 will not become 

effective until the first day of the first 

calendar quarter three months after 

regulatory approval is obtained, and 

EOP–005–2 and EOP–006–2 approved 

in this Final Rule will not become 

effective until 24 months after the first 

day of the first quarter after applicable 

regulatory approval. 

2. ‘‘Blackstart’’ capability refers to the 

ability of a generating unit or station to 

start operating and delivering electric 

power without assistance from the 

electric system. Blackstart units are 

essential to restart generation and 

restore power to the grid in the event of 

an outage. As discussed below, NERC 

proposes to define ‘‘Blackstart Resource’’ 

as ‘‘a generating unit(s) and its 

associated set of equipment which has 

the ability to be started without support 

from the System or is designed to 

remain energized without connection to 

the remainder of the System, with the 

ability to energize a bus. * * *’’ 

3. In Order No. 693, the Commission 

determined that it would not take action 

on certain proposed Reliability 

Standards that required supplemental 

information from a Regional Entity. 

Such Reliability Standards refer to 

regional criteria or procedures that had 

not been submitted to the Commission 

for approval and, as such, are referred 

to as ‘‘fill-in-the-blank’’ standards.2

Pending Reliability Standard EOP–007– 

0 is one such fill-in-the-blank standard. 

The Reliability Standards approved 

herein provide a standardized, national 

approach to address the Commission’s 

concerns regarding pending EOP–007–0, 

as set forth in Order No. 693. Thus, in 

addition to the retirement of certain 

currently effective EOP Reliability 

Standards, we also approve the 

withdrawal of pending Reliability 

Standard EOP–007–0. 

I. Background 

4. On March 16, 2007, the 

Commission issued Order No. 693, 

approving 83 of the 107 Reliability 

Standards filed by NERC,3 including the 

Reliability Standards: EOP–001–0, EOP– 

005–1, EOP–006–1, and EOP–009–0.4

The Commission neither approved nor 

remanded EOP–007–0 because it 

applied only to regional reliability 

organizations, but Order No. 693 did 

provide guidance for the ERO’s further 

consideration of the Reliability 

Standard.5 In addition, under section 

215(d)(5) of the FPA, the Commission 

directed NERC to develop modifications 

to the EOP Reliability Standards to 

address certain issues identified by the 

Commission. At issue in the immediate 

proceeding are two new EOP standards, 

EOP–005–2 and EOP–006–2 that would 

replace the currently effective 

Reliability Standards EOP–005–1, EOP– 

006–1, and EOP–009–0, pending 

Standard EOP–007–0, and necessitate a 

conforming change in EOP–001–0. 

A. Currently Effective EOP Reliability 

Standards 

Reliability Standard EOP–005–1 

5. Currently effective Reliability 

Standard EOP–005–1 requires 

transmission operators, balancing 

authorities, and reliability coordinators 

to have a restoration plan, test the plan, 

train operating personnel in the 

restoration plan, and have the ability to 

restore the Interconnection using the 

plans following a blackout. In Order No. 

693, the Commission directed the ERO 

to develop, through the Reliability 

Standard development process, a 

modification to EOP–005–1 that 

identifies time frames for training and 

review of restoration plan requirements 

to simulate contingencies and prepare 

operators for anticipated and unforeseen 

events.6 The Commission also directed 

the ERO to consider various 

commenters’ suggestions in future 

revisions of the Reliability Standard.7

Reliability Standard EOP–006–1 

6. In Order No. 693, the Commission 

also approved Reliability Standard 

EOP–006–1 addressing reliability 

coordination and system restoration. 

The Reliability Standard sets 

requirements for reliability coordinators 

during system restoration and requires 

that they have a coordinating role to 

ensure reliability is maintained during 

system restoration. Under section 215 of 

the FPA, the Commission directed the 

ERO to develop a modification to EOP– 

006–1 to ensure that the reliability 

coordinator is involved in the 

development and approval of system 

restoration plans.8

Pending Reliability Standard 

EOP–007–0 

7. Pending Reliability Standard EOP– 

007–0 deals with establishing, 

maintaining and documenting regional 

blackstart capability plans. In Order No. 

693, the Commission did not act on 

EOP–007–0 pending NERC’s providing 

additional information.9 The 

Commission, however, directed the ERO 

to consider various commenters’ 

suggestions relating to assigning 

compliance obligations directly to the 

entities that provide the pertinent data 

rather than to the Regional Entity, 

placing responsibility for the regional 

blackstart plan with the reliability 

coordinator, recognizing that nuclear 

units have no blackstart capability, 

revising the definition of a blackstart 

unit, and committing arrangements for 

coordinating blackstart capability to 

contracts.10

Reliability Standard EOP–009–0 

8. Currently effective Reliability 

Standard EOP–009–0 deals with 

implementing and documenting testing 


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Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 16279 

11 Id. P 674, 676. 

12North American Electric Reliability Corp., Dec. 

31, 2009 Petition for Approval of Three Emergency 

Preparedness and Operations Reliability Standards 

and One New Glossary Term and for Retirement of 

Five Existing Reliability Standards and One 

Glossary Term. The three Reliability standards are 

included as Exhibit A to NERC’s Petition. In 

addition, under 18 CFR 40.3 of the Commission’s 

regulations, all Commission-approved Reliability 

Standards are available on NERC’s Web site at 

http://www.nerc.com/page.php?cid=2√20. See 18 

CFR 40.3. 

13Concurrent with its filing in this Docket, NERC 

filed a petition in Docket No. RM10–15–000 seeking 

approval of certain Interconnection Reliability 

Operations and Coordination (IRO) Reliability 

Standards. As part of its IRO filing, NERC proposed 

to retire Requirement R2 of EOP–001–0. Each 

petition proposes unique changes to EOP–001–0 

reflecting the distinct issues addressed by the 

respective Reliability Standards drafting teams. In 

this Final Rule, the Commission is addressing 

Version 2 of EOP–001 contained in Exhibit B of the 

NERC Petition which reflects both the IRO and the 

EOP proposed changes. 

14NERC Petition at 4. 

15 Id. at 5. 

16 Id. 

17Reliability Standard EOP–001–1, Section A.3. 

(Purpose). 

18Reliability Standard EOP–005–2, Section A.4. 

(Purpose). 

19Reliability Standard EOP–006–2, Section A.3. 

(Purpose). 

of blackstart generating units. In Order 

No. 693, the Commission directed the 

ERO to consider suggestions for 

improvements raised during the 

comment period. One commenter stated 

the Reliability Standard should provide 

details on what constitutes a blackstart 

test and another stated that NERC 

should consolidate the Reliability 

Standard with EOP–007–0.11

B. NERC Petition 

9. In a December 31, 2009 filing 

(NERC Petition),12 NERC requests 

Commission approval of its proposed 

definition of the term ‘‘Blackstart 

Resource’’ and proposed Reliability 

Standards EOP–001–1 (Emergency 

Operating Planning),13 EOP–005–2 

(System Restoration from Blackstart 

Resources), and EOP–006–2 (System 

Restoration Coordination). NERC also 

seeks to concurrently retire four 

currently effective Reliability Standards: 

EOP–001–0, EOP–005–1, EOP–006–1, 

and EOP–009–0 as well as the definition 

of ‘‘Blackstart Capability Plan’’ and 

withdraw pending Reliability Standard 

EOP–007–0. 

10. NERC states that the proposed 

Reliability Standards ‘‘represent 

significant revision and improvement 

from the current set of enforceable 

standards’’ and address the 

Commission’s directives in Order No. 

693 related to the EOP standards.14

NERC explains that, among other 

enhancements, ‘‘[t]he proposed revisions 

now clearly delineate the 

responsibilities of the Reliability 

Coordinator and Transmission Operator 

in the restoration process and 

restoration planning.’’ 15 NERC describes 

the proposed Reliability Standards as 

providing ‘‘specific requirements for 

what must be in a restoration plan, how 

and when it needs to be updated and 

approved, what needs to be provided to 

operators and what training is necessary 

for personnel involved in restoration 

processes.’’ 16

Proposed Definition of Blackstart 

Resource 

11. NERC requests approval of the 

term ‘‘Blackstart Resource’’ and the 

concurrent retirement of the term 

‘‘Blackstart Capability Plan.’’ The 

proposed definition of ‘‘Blackstart 

Resource’’ is: 

A generating unit(s) and its associated set 

of equipment which has the ability to be 

started without support from the System or 

is designed to remain energized without 

connection to the remainder of the System, 

with the ability to energize a bus, meeting the 

Transmission Operator’s restoration plan 

needs for real and reactive power capability, 

frequency and voltage control, and that has 

been included in the Transmission 

Operator’s restoration plan. 

The term ‘‘Blackstart Capacity Plan’’ is 

currently used solely in EOP–007–0 and 

EOP–009–0, both of which are replaced 

with proposed Reliability Standards 

EOP–005–2 and EOP–006–2. 

Proposed Reliability Standard EOP– 

001–1 

12. Proposed Reliability Standard 

EOP–001–1 contains seven 

requirements for the stated purpose of 

requiring each transmission operator 

and balancing authority to develop, 

maintain, and implement a set of plans 

to mitigate operating emergencies and to 

coordinate these plans with other 

transmission operators, balancing 

authorities, and the reliability 

coordinator.17 It modifies EOP–001–0 

by deleting Requirement R3.4, which 

requires transmission operators and 

balancing authorities to develop, 

maintain and implement restoration 

plans, because proposed Reliability 

Standards EOP–005–2 and EOP–006–2 

incorporate and expand upon this 

Requirement. 

Proposed Reliability Standard EOP– 

005–2 

13. Proposed Reliability Standard 

EOP–005–2 contains eighteen 

requirements for the stated purpose of 

ensuring that plans, facilities, and 

personnel are prepared to enable system 

restoration from Blackstart Resources, 

and to ensure reliability is maintained 

during restoration and priority is placed 

on restoring the Interconnection.18 The 

proposed Reliability Standard applies to 

transmission operators, generation 

operators, and transmission owners and 

distribution providers identified in the 

transmission operator’s restoration plan. 

Requirement R1 requires each 

transmission operator to have a 

reliability coordinator-approved 

restoration plan utilizing Blackstart 

Resources and details the scope and 

elements of such a plan. Requirement 

R2 instructs each transmission operator 

to provide entities that have a role in the 

restoration plan with a description of 

their roles and tasks. Requirements R3 

through R6 address annual plan 

reviews, updating practices, location of 

plans and plan verification. Following a 

disturbance, Requirements R7 and R8 

provide guidance on following the plan 

or making needed adjustments and 

coordinating when re-synchronizing 

two systems together. Requirement R9 

describes testing information the 

transmission operator must have to 

verify the Blackstart Resources meet 

required expectations. Requirements 

R10 through R12 cover system 

restoration training requirements for 

system operators and field switching 

personnel. Blackstart Resource 

agreements between the transmission 

operator and generator operator, or 

mutually agreed upon procedures or 

protocols are addressed in Requirement 

R13. Duties of a generator owner with a 

Blackstart Resource are provided in 

Requirements R14 through R18, which 

address operating procedures, change 

notification, testing for each Blackstart 

Resource and training of operating 

personnel on Blackstart Resources. 

Proposed Reliability Standard EOP– 

005–2 is intended to supersede all of 

currently effective Reliability Standard 

EOP–005–1. 

Proposed Reliability Standard EOP– 

006–2 

14. Proposed Reliability Standard 

EOP–006–2 contains ten requirements 

with the stated purpose of ensuring that 

the reliability coordinator establishes 

plans and prepares personnel to enable 

effective coordination of the system 

restoration process, to maintain 

reliability during restoration, and to 

place priority on restoring the 

Interconnection.19 Requirement R1 

requires reliability coordinators to have 

restoration plans that utilize Blackstart 

Resources and specifies the scope and 

elements of such plans. Requirement R2 


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16280 Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 

20System Restoration Reliability Standards, 

Notice of Proposed Rulemaking, 75 FR 71625 (Nov. 

24, 2010), FERC Stats. & Regs. ¶ 32,666 (2010). 

21NERC, The Edison Electric Institute (EEI), 

American Public Power Association (APPA), the 

ISO/RTO Council (IRC), Pacificorp, City of Santa 

Clara, California (Santa Clara), Bonneville Power 

Administration (BPA), and NorthWestern 

Corporation (NorthWestern) filed comments. 

Wisconsin Electric Power Company filed 

supporting EEI’s comments. 

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

covers distribution of the reliability 

coordinator’s restoration plan. 

Requirements R3 through R5 provide for 

review of the reliability coordinator’s 

restoration plan and the plans of each 

neighboring reliability coordinator and 

each transmission operator located in 

the reliability coordinator’s area. Any 

conflicts between neighboring reliability 

coordinators’ plans are to be resolved 

within thirty days, and transmission 

operators’ plans shall be approved or 

disapproved, with stated reasons, 

within thirty days of receipt by the 

reliability coordinator. Requirement R6 

requires that the reliability coordinator 

must maintain copies of restoration 

plans in its primary and backup control 

rooms. Requirements R7 and R8 

describe the roles of reliability 

coordinators to coordinate restoration 

efforts and authorize re-synchronization 

of ‘‘island’’ areas. Requirements R9 and 

R10 address training and participation 

in annual drills, exercises and 

simulations. Proposed Reliability 

Standard EOP–006–2 is intended to 

supersede all of currently effective 

Reliability Standard EOP–006–1. 

C. Notice of Proposed Rulemaking 

15. On November 17, 2010, the 

Commission issued its Notice of 

Proposed Rulemaking (NOPR) 

proposing to approve the three proposed 

EOP Reliability Standards, EOP–001–1, 

EOP–005–2, and EOP–006–2 and 

defined term Blackstart Resource (and 

the retirement of the four superseded 

standards, EOP–001–0, EOP–005–1, 

EOP–006–1, and EOP–009–0, the 

definition of ‘‘Blackstart Capability 

Plan,’’ and the ERO’s withdrawal of 

EOP–007–0).20 With respect to proposed 

Reliability Standard EOP–005–2, the 

NOPR proposed to direct NERC to 

modify the Standard to address the 

Commission’s concern regarding the 

periodic testing of telecommunication 

facilities needed to implement 

restoration plans. In addition, the 

Commission sought comment on: (i) 

What is intended by the term ‘‘unique 

tasks’’ as used in the context of proposed 

Requirement R11 of EOP–005–2; (ii) 

whether guidance should be provided 

regarding the term, and if so, how it 

should be provided; and (iii) whether 

those tasks should be indentified in 

each transmission operator’s restoration 

plan. With respect to proposed 

Reliability Standard EOP–006–2, the 

NOPR sought comment as to why the 

Standard does not require reliability 

coordinators to maintain a database of 

Blackstart Resources as is required of 

Regional Entities under currently 

effective EOP–007–0 and whether such 

a requirement would be beneficial. The 

NOPR also sought comment on: (i) 

Whether reliability coordinators should 

be required to verify their restoration 

planning through actual events, steady 

state and dynamic simulations or 

testing; and (ii) how a transmission 

operator should proceed when its 

restoration plan is rejected by a 

reliability coordinator. Lastly, the NOPR 

proposed that the ERO collect data on 

the performance of system restoration 

exercises conducted by transmission 

operators and reliability coordinators to 

assist the ERO and Commission in 

identifying the effectiveness of 

restoration plans, establishing best 

practices, and determining the effects on 

personnel performance. 

16. In response to the NOPR, 

comments were filed by nine interested 

parties.21 These comments assisted us in 

the evaluation of the NERC’s proposal. 

In the discussion below, we address the 

issues raised by these comments. 

II. Discussion 

A. Approval of Proposed Reliability 

Standards 

17. In the NOPR, the Commission 

proposed to approve the three EOP 

Reliability Standards and the glossary 

term filed by NERC in this proceeding. 

None of the nine interested parties filing 

comments to the NOPR objects to such 

an approval. For the reasons described 

below, the Commission adopts the 

NOPR proposal and approves Reliability 

Standards EOP–001–1, EOP–005–2, and 

EOP–006–2 as well as the proposed 

glossary term ‘‘Blackstart Resource’’ as 

just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest.22 EOP–005–2 and 

EOP–006–2 clarify the responsibilities 

of the reliability coordinator and 

transmission operator in the restoration 

process and restoration planning and 

address the Commission’s directives in 

Order No. 693 related to the EOP 

Standards. By enhancing the rigor of the 

restoration planning process, the 

Reliability Standards represent an 

improvement from the current 

Standards and will improve the 

reliability of the Bulk-Power System. 

The Commission is not directing any 

modifications to the three new 

Reliability Standards. Nevertheless, as 

discussed below, commenters raised 

several issues for consideration, at the 

time these standards are next revisited, 

which we believe could improve these 

new Reliability Standards. The 

Commission also approves NERC 

retiring the four currently effective 

Reliability Standards, EOP–001–0, EOP– 

005–1, EOP–006–1, and EOP–009–0 as 

well as the definition of ‘‘Blackstart 

Capability Plan’’ and withdrawing 

pending Reliability Standard EOP–007– 

0 concurrent with the effectiveness of 

the EOP–001–1, EOP–005–2, and EOP– 

006–2 and the definition of the term 

‘‘Blackstart Resource.’’ 

B. Vagueness of Term ‘‘Unique Tasks’’ 

18. Requirement R11 of EOP–005–2 

requires that a minimum of two hours 

of system restoration training be 

provided every two years to field 

switching personnel performing ‘‘unique 

tasks’’ associated with the transmission 

operator’s restoration plan. In the 

NOPR, the Commission expressed 

concern that the applicable entities may 

not understand what the term ‘‘unique 

tasks’’ means. We requested comment on 

what is intended by that term and on 

whether guidance should be provided to 

the transmission operators, transmission 

owners, and distribution providers who 

are responsible for providing training. In 

addition, the NOPR sought comment as 

to whether the unique tasks should be 

identified in each transmission 

operator’s restoration plan. 

Comment 

19. NERC comments that the term 

‘‘unique tasks’’ is not intended to have 

any meaning beyond the dictionary 

definition of the words. Everyday tasks 

of field switching personnel are not 

considered unique, but tasks not 

included in the person’s normal duties 

(e.g., operation of a synchroscope) 

would be considered unique. NERC and 

APPA do not perceive a reliability 

benefit in requiring identification of 

unique tasks in restoration plans. NERC 

acknowledges that it could promote the 

development of guidance to aid entities 

in complying with Requirement R11. 

20. EEI comments that while it would 

be difficult to define ‘‘unique tasks’’ in 

a manner that could be broadly applied 

to affected entities, the standards 

drafting team believed that the term was 

clearly understood as a practical matter. 

Companies should be afforded 

discretion to determine how the term is 

defined within their restoration plans, 

but, to the extent that compliance issues 

arise, EEI would encourage NERC to 

consider developing compliance 


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23NERC at 4–5. 

24Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 478–493. 

guidance as needed. IRC also believes 

the term is generally understood by the 

applicable entities and that it is 

appropriate for each transmission 

operator’s restoration plan to identify 

the particular tasks for which training is 

required. 

21. APPA states that the diversity of 

entities and their specific approaches to 

system restoration prevented the 

standard drafting team from developing 

guidance on the term but agrees that 

registered entities could benefit from a 

best practices document that provides 

examples of unique tasks. 

22. Santa Clara comments that a onesize-fits-all definition would not be 

helpful, and the affected entities should 

define unique tasks on a case-by-case 

basis. It agrees that unique tasks should 

be included within the transmission 

operator’s restoration plan. Pacificorp 

comments that training should be 

provided to field switching personnel 

performing any restoration tasks 

associated with implementing the 

transmission operator’s restoration plan. 

Addressing each sub-Requirement of 

Requirement R1 would provide an 

appropriate framework for a system 

restoration training program. Pacificorp 

and NorthWestern oppose additional 

guidance or requirements in the 

Standard. BPA, on the other hand, is 

unsure what is intended by the term 

‘‘unique tasks’’ and supports a specific 

definition to avoid any ambiguity. 

Commission Determination 

23. Based on NERC’s comment that 

the term ‘‘unique tasks’’ is to be 

understood in accordance with the 

normal meaning of the words and the 

majority of the commenters’ assertions 

that the variety of approaches to system 

restoration precludes greater specificity, 

we find that the term conveys as much 

precision as circumstances allow. To the 

extent that it would be helpful to the 

affected entities to specify in a 

transmission operator’s restoration plan 

which tasks are deemed unique, the 

entities are encouraged to do so, but the 

Commission does not require such 

specificity at this time. 

24. Both EEI and APPA recognize 

potential benefit in the development of 

further guidance as to the term ‘‘unique 

tasks,’’ and BPA is uncertain as to the 

meaning of the term and consequently 

unsure as to how to demonstrate 

compliance with its training obligation. 

NERC, in its comments about the term, 

states that it ‘‘could promote the 

development of a guideline to aid 

registered entities in complying with 

Requirement R11.’’23 The Commission 

notes that this Reliability Standard will 

not become effective for at least 24 

months, during which time ambiguities 

in language or differences of opinion 

among affected entities may be resolved 

in practical ways. Once the Standard is 

effective, if industry determines that 

ambiguity with the term arises, it would 

be appropriate for NERC to consider its 

proposal to develop a guideline to aid 

entities in their compliance obligations. 

C. Telecommunication Facility Testing 

25. Requirement R5 of Reliability 

Standard EOP–005–1 provides for 

periodic testing of telecommunication 

facilities needed to implement 

restoration plans, but this Requirement 

has no counterpart in EOP–005–2. In the 

NOPR, the Commission proposed 

requiring the ERO to develop a 

modification to EOP–005–2 to address 

the Commission’s concern that entities 

involved in system restoration ensure 

restoration-specific telecommunications 

equipment, phone lists, and protocols 

are tested as part of ongoing restoration 

preparedness. The Commission further 

stated its concern that, in light of the 

importance of communication to the 

restoration process, testing should be 

done more frequently than during 

annual drills, exercises or simulations 

as is required under Reliability Standard 

EOP–005–1. 

Comments 

26. Each of the commenters opposes 

adding a telecommunications 

requirement to EOP–005–2 on the basis 

that such a requirement would be 

redundant given Communications 

Reliability Standard COM–001–1.1, 

which requires testing of routine 

communication facilities on an on-going 

basis. Several comments noted that 

duplicative requirements can lead to 

potential confusion. 

Commission Determination 

27. Reliability Standard COM–001–1 

does not apply to generation operators 

or distribution providers.24 Further, we 

do not accept that each entity whose 

telecommunications facilities will be 

needed during the system restoration 

process is currently subject to COM– 

001–1.1 Requirement R2 which 

provides that ‘‘[e]ach Reliability 

Coordinator, Transmission Operator and 

Balancing Authority shall manage, 

alarm, test and/or actively monitor vital 

telecommunications facilities. Special 

attention shall be given to emergency 

telecommunications facilities and 

equipment not used for routine 

communications.’’ 

28. NERC notes in its comments that 

the Reliability Coordination Standard 

Drafting Team is currently working on 

Project 2006–06 to develop a set of 

revisions to Reliability Standard COM– 

001–1.1 to tighten requirements relating 

to communication capabilities. The 

Commission believes the objectives of 

this project in managing, alarming, 

testing and/or actively monitoring vital 

primary and emergency 

telecommunication facilities will close 

this gap in the Reliability Standard after 

it is completed and approved. 

Accordingly, consistent with NERC’s 

comments on its current project and 

concerns not to create redundancy in 

development of Reliability Standards, 

NERC should close the gap in the 

applicability of the draft COM–001–2 so 

it addresses generation operators and 

distribution providers. 

D. Emergency Operations Planning 

29. Reliability Standard EOP–005–2 

requires each transmission operator to 

identify each blackstart resource and its 

characteristics, but this requirement has 

no counterpart for reliability 

coordinators in EOP–006–2. The 

Commission expressed concern and 

invited comment in the NOPR on 

whether the absence of a required list of 

its Blackstart Resources could deny the 

reliability coordinator a potentially 

useful tool in maintaining reliability. 

Comments 

30. NERC notes that the transmission 

operator, not the reliability coordinator, 

maintains direct contact with the 

blackstart resources, and reliability 

coordinators have sufficient authority to 

request information needed to identify 

blackstart resources should such 

information be required. NERC, EEI, 

IRC, and APPA do not believe a 

requirement to maintain a database of 

blackstart resources would improve 

reliability. Santa Clara, however, 

requests that the Commission direct 

NERC to revise Requirement R2 of 

Reliability Standard EOP–005–2 to 

specify that transmission operators 

provide copies of their restoration plans 

to those entities included in the plan 

within 60 days of the plan’s approval by 

the appropriate reliability coordinator to 

ensure that resources identified in the 

plan are capable of complying with the 

plan. 

Commission Determination 

31. Since a reliability coordinator 

obtains copies of all its constituent 

transmission operators’ restoration 

plans and has the ability to obtain 


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16282 Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 

information regarding the identity and 

characteristics of blackstart resources 

from its transmission operators, we 

agree there is no reliability need for it 

to maintain a duplicative database. With 

regard to Santa Clara’s request, we 

believe that the determination whether 

resources in a restoration plan are 

capable of complying with the plan is 

made during the transmission operator’s 

development of its plan as required by 

Requirement R1, not once the plan is 

approved by the reliability coordinator. 

For this reason, we do not see a need to 

direct the modification to Requirement 

R2 that Santa Clara requests. 

E. System Restoration Coordination 

32. Reliability Standard EOP–005–2 

requires each transmission operator to 

verify that its restoration plan achieves 

its intended function. There is no 

similar requirement in EOP–006–2 

regarding the reliability coordinator’s 

restoration plan. The Commission 

sought comment on whether the same or 

a similar requirement should apply to 

reliability coordinators. In addition, the 

Standard also requires reliability 

coordinators to approve, or disapprove 

with written reasons, the restoration 

plans of each of their constituent 

transmission operators. The 

Commission invited comment as to how 

a transmission operator should proceed 

when its restoration plan is rejected by 

a reliability coordinator. 

Comments 

33. NERC, EEI, and IRC comment that 

a reliability coordinator’s restoration 

plan is essentially a compilation of the 

restoration plans of its constituent 

transmission operators. Given that EOP– 

005–2 requires transmission operators to 

verify their restoration plans and that 

EOP–006–2 requires reliability 

coordinators to conduct system 

restoration drills with their constituent 

transmission operators and generation 

owners, requiring further verification of 

the same plans by the reliability 

coordinator would be duplicative and 

not provide additional reliability 

benefit. 

34. With respect to how a 

transmission operator should proceed 

when its reliability coordinator rejects 

its restoration plan, NERC states that 

when a restoration plan is rejected by a 

reliability coordinator, the reliability 

coordinator is required to supply one or 

more reasons for its rejection, and the 

transmission operator should then be 

able to re-submit a revised plan. NERC 

does not believe it is necessary to 

document this process in additional 

requirements since the dialogue 

between the two entities is no different 

than the routine coordination that 

normally occurs between the 

transmission operator and its reliability 

coordinator. EEI, APPA, and IRC agree 

that there is no need for additional 

procedures to be spelled out. 

35. IRC, BPA, and Santa Clara all 

comment that the reliability coordinator 

should be the final authority to resolve 

conflicts. Santa Clara nevertheless states 

that if the transmission operator and 

reliability coordinator cannot resolve 

their differences because the 

transmission operator believes 

compliance with the reliability 

coordinator’s decision is infeasible, the 

transmission operator should be 

allowed to appeal either to the Regional 

Entity or, in the case of the Western 

Interconnect, the dispute should be 

brought to NERC. 

36. EEI observes that the two-year 

implementation period for these 

Standards will likely provide sufficient 

time to resolve any differences in order 

for a reliability coordinator to approve 

a transmission operator’s initial 

restoration plan. Any subsequent 

rejection of a revised restoration plan 

will not result in a reliability gap since 

the initial plan will remain in place. EEI 

further notes that any rejection of a 

restoration plan by a reliability 

coordinator will necessarily be based on 

generic reliability engineering criteria 

readily understood by the transmission 

operator. Pacificorp, on the other hand, 

notes that the requirement that the 

reliability coordinator give stated 

reasons for any disapproval of a 

submitted restoration plan does not 

ensure the reasons will specify the 

circumstances under which a 

transmission operator should revise its 

plan. Pacificorp states that a reliability 

coordinator must have formal criteria 

for reviewing, approving and 

disapproving restoration plans and 

standard procedures for those plans to 

be revised and resubmitted for review. 

Pacificorp also suggest a modification to 

Requirement R5 to provide that a 

transmission operator’s submitted 

restoration plan shall be deemed 

approved if the reliability coordinator 

fails to approve or disapprove the plan 

within the required 30 days. 

Commission Determination 

37. We accept the commenters’ 

position that requiring verification of 

the reliability coordinators’ restoration 

plan through a requirement in EOP– 

006–2 would be largely duplicative. As 

commenters point out, Reliability 

Standard EOP–006–2 requires reliability 

coordinators to conduct system 

restoration drills including their 

constituent transmission operators and 

generation owners. Such drills, 

exercises or simulations, together with 

the verifications carried out by the 

transmission operators of their 

restoration plans and approval of their 

plans by the reliability coordinators 

under EOP–005–2, serve as verification 

of the reliability coordinators’ plans and 

as such, should serve to identify 

difficulties in a reliability coordinator’s 

restoration plan. 

38. We agree with EEI that the basis 

on which a reliability coordinator 

rejects a restoration plan will 

necessarily be based on generic 

engineering criteria easily understood 

by the transmission operator. We also 

agree with those commenters who 

reaffirm that the ultimate arbiter of 

coordination and compatibility of 

transmission operators’ restoration 

plans is the reliability coordinator. For 

these reasons, we do not see a need to 

direct modifications as Pacificorp and 

Santa Clara suggest that could 

circumvent the reliability coordinator’s 

authority concerning the approval or 

disapproval of a restoration plan. 

However, we agree with Pacificorp that 

Reliability Standard EOP–006–2, which 

establishes requirements to enable 

coordinated system restoration and 

ensure reliability is maintained during 

system restoration, is not the 

appropriate place to include any 

specific criteria or procedures for the 

review and revision of transmission 

operators’ restoration plans. We 

recognize that documenting such 

criteria and procedures may have utility 

in facilitating the settlement of 

disagreements when a reliability 

coordinator rejects a transmission 

operator’s restoration plan. Nonetheless, 

we leave it to the ERO Reliability 

Standard development process to 

determine whether the merit is 

sufficient to compel the development of 

such criteria or procedures. 

F. Data Reporting 

39. Given the importance of effective 

blackstart and restoration plans and 

well-trained personnel, the NOPR 

proposed that the ERO collect data on 

the performance of system restoration 

exercises and make such data available 

to transmission operators, reliability 

coordinators and the Commission. This 

data could then be used to identify the 

effectiveness of restoration plans and 

help identify improvements to enhance 

restoration. The Commission sought 

comment on the proposed data 

collection. 

Comments 

40. NERC notes that formal 

debriefings are held after each required 


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25North American Electric Reliability 

Corporation, Rules of Procedure 85–87 (2011), 

available at http://www.nerc.com/files/ 

NERC_Rules_of_Procedure_ EFFECTIVE_ 

20110101.pdf. 

26 Docket No. RR08–4–005 comprises NERC’s 

March 5, 2010 Violation Severity Level Compliance 

Filing submitted in response to Order No. 722 and 

an August 10, 2009 informational filing in which 

NERC proposes assigning VRF and VSL only to the 

main Requirements in each Reliability Standard 

and not to the sub-requirements. 

27 44 U.S.C. 3507(d). 

28 5 CFR 1320.11. 

drill and is unclear whether there would 

be any additional reliability benefit 

arising from the data collection 

contemplated in the NOPR. EEI 

proposes that companies should be 

allowed to gather experience on the new 

requirements before undertaking data 

collection efforts and points out that the 

North American Transmission Forum 

(NATF) would be an appropriate venue 

for discussions on the efficacy of 

various training experiences. BPA and 

NorthWestern also cite NATF as an 

appropriate venue to share best 

practices. BPA views its restoration 

information as extremely sensitive and 

perceives risk that such information 

could fall into the wrong hands. 

41. NERC, EEI, APPA, Pacificorp, and 

NorthWestern question the reliability 

benefit of creating such a database 

compared to the burden it would 

impose on the industry. NERC asks 

whether developing such a database 

would direct industry resources where 

they can best serve reliability. IRC does 

not see the value of the proposed data 

gathering, but notes section 1600— 

Requests for Data or Information of 

NERC’s Rules of Procedure 25 could be 

an appropriate means of collecting data 

without creating an ongoing 

requirement. 

Commission Determination 

42. The Commission agrees with 

NERC that the formal debriefing of 

system restoration drills, exercises and 

simulations can capture lessons learned 

and identify best practices. But lessons 

learned in such debriefings are not 

necessarily communicated to all who 

might benefit from them. In addition, 

the Commission understands that NATF 

may be an appropriate forum to discuss 

industry activity and best practices, but 

we continue to believe that there would 

be a reliability benefit in the ERO 

aggregating and disseminating lessons 

learned derived from restoration drills, 

exercises and simulations. Nevertheless, 

we will allow the industry to develop 

some experience with the new 

Reliability Standards and then review 

whether or not to pursue this matter 

under section 39.2(d) of the 

Commission’s regulations and the use of 

Requests for Data or Information under 

section 1600 of NERC’s Rules of 

Procedure or through some other means. 

G. Violation Risk Factors/Violation 

Severity Levels 

43. In the NOPR, the Commission 

proposed deferring action on the 

proposed violation risk factors (VRF) 

and violation severity levels (VSL) for 

the proposed Reliability Standards until 

the Commission acts on NERC’s 

pending petition in Docket No. RR08–4– 

005, in which NERC proposes a ‘‘rollup’’ approach for VRF and VSL 

assignments by which NERC would 

only assign VRF and VSL to the main 

requirements and not to subRequirements.26 Subsequent to the 

NOPR, on December 1, 2010, NERC 

made a compliance filing to the 

Commission in Docket No. RR08–04– 

006 submitting new VSL to supersede 

those presented in the NERC Petition. 

Commission Determination 

44. No comments were received 

regarding this matter. Accordingly, the 

Commission will defer discussion on 

the proposed violation risk factors and 

violation severity levels assigned to 

EOP–005–2 and EOP–006–2 until after 

the Commission issues a final order 

acting on NERC’s petition in Docket No. 

RR08–4–005 and Docket No. RR08–4– 

006. 

III. Information Collection Statement 

45. The following collections of 

information contained in this Reliability 

Standard have been submitted to the 

Office of Management and Budget 

(OMB) for review under section 3507(d) 

of the Paperwork Reduction Act of 

1955.27 OMB’s regulations require OMB 

to approve certain information 

collection requirements imposed by 

agency rule.28

46. The Commission solicited 

comments on the need for and the 

purpose of the information contained in 

these three Emergency Operations and 

Performance Reliability Standards and 

the corresponding burden to implement 

them. The commission received 

comments on its proposed data 

reporting requirement regarding the 

performance of system restoration 

exercises which we address in this Final 

Rule. The Commission has not directed 

any modifications to the Requirements 

in the three Reliability Standards being 

approved. As a result of this Final Rule 

the annual burden will increase by an 

estimated 47,472 hours. This is a 

reduction from the burden estimates 

provided in the NOPR, with respect to 

reporting data to NERC; however, we 

have not similarly reduced the 

estimated time expended by reliability 

coordinators on recordkeeping in order 

to better reflect their enhanced 

involvement in the planning process. 

47. Burden Estimate: The estimated 

burden and for the requirements in this 

Final Rule follow: 

FERC–725A data collection Number of 

respondents 

Number of 

annual 

responses per 

respondent 

Hours per respondent per 

response Total annual hours 

(A) (B) (C) (A × B × C) 

Reliability Coordinators data retention ...................... 26 2 Recordkeeping: 8 ............. Recordkeeping: 416. 

Transmission operators reporting data to their reliability coordinator and reducing blackstart arrangements to writing.176 1 Compliance: 116 ..............

Recordkeeping: 16 ...........

Compliance: 20,416. 

Recordkeeping: 2,816. 

Generator operator system restoration responsibilities including testing and maintaining records.230 1 80 ...................................... 18,400. 

Transmission owner and distribution provider training and recordkeeping.678 1 8 ........................................ 5,424. 

Total .................................................................... ........................ ........................ ........................................... 47,472 hours. 


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29Regulations Implementing the National 

Environmental Policy Act, Order No. 486, 52 FR 

47897 (Dec. 17, 1987), FERC Stats. & Regs., 

Regulations Preambles 1986–1990 ¶ 30,783 (1987). 

30 18 CFR 380.4(a)(5). 

31 5 U.S.C. 601–12. 

32 13 CFR 121.101. 

33 13 CFR 121.201, Sector 22, Utilities & n. 1. 

• Total Estimated Annual Hours for 

Collection: (Reporting/Compliance + 

recordkeeping) = 47,472 hours. 

• Reporting/Compliance = 44,240 

hours @ $132/hour = $5,839,680. 

• Recordkeeping = 3,232 hours @ 

$17/hour = $54,944. 

• Total Cost = $5,894,624. 

• Title: Mandatory Reliability 

Standards for the Bulk-Power System. 

• Action: FERC 725A, Proposed 

Modification to FERC–725A. 

• OMB Control No: 1902–0244. 

• Respondents: Business or other for 

profit, and/or not for profit institutions. 

• Frequency of Responses: On 

occasion. 

• Necessity of the Information: This 

Final Rule would approve revised 

Reliability Standards that modify the 

existing requirement for system 

restoration from a blackstart. The 

proposed Reliability Standards require 

some entities to commit agreements or 

understandings to writing and/or to 

draft written procedures, and retain 

records. Other entities may have to 

produce and maintain training 

materials. 

48. Interested persons may obtain 

information on the reporting 

requirements by contacting: Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426 

[Attention: Ellen Brown, Office of the 

Executive Director, e-mail: 

DataClearance@ferc.gov, Phone: (202) 

502–8663, fax: (202) 273–0873]. 

Comments on the requirements of this 

order may also be sent to the Office of 

Information and Regulatory Affairs, 

Office of Management and Budget, 

Washington, DC 20503 [Attention: Desk 

Officer for the Federal Energy 

Regulatory Commission]. For security 

reasons, comments should be sent by 

e-mail to OMB at 

oira_submission@omb.eop.gov. Please 

reference OMB Control Number 1902– 

0244 and the docket number of this 

rulemaking in your submission. 

IV. Environmental Analysis 

49. 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.29 The action taken in the 

Final Rule falls within the categorical 

exclusion in the Commission’s 

regulations for rules that are clarifying, 

corrective or procedural, for information 

gathering, analysis, and 

dissemination.30 Accordingly, neither 

an environmental impact statement nor 

an environmental assessment is 

required. 

V. Regulatory Flexibility Act 

50. The Regulatory Flexibility Act of 

1980 (RFA) 31 generally requires a 

description and analysis of final rules 

that will have significant economic 

impact on a substantial number of small 

entities. The RFA mandates 

consideration of regulatory alternatives 

that accomplish the stated objectives of 

a proposed rule and that minimize any 

significant economic impact on a 

substantial number of small entities. 

The Small Business Administration’s 

(SBA) Office of Size Standards develops 

the numerical definition of a small 

business.32 The SBA has established a 

size standard for electric utilities, 

stating that a firm is small if, including 

its affiliates, it is primarily engaged in 

the transmission, generation and/or 

distribution of electric energy for sale 

and its total electric output for the 

preceding twelve months did not exceed 

four million megawatt hours.33

51. Many of the entities to which the 

requirements of this rule would apply 

do not fall within the definition of small 

entities, but most transmission owners, 

and most distribution providers would 

be deemed small entities. The proposed 

Reliability Standards clarify the 

elements of restoration plans and 

training requirements and give 

reliability coordinators a greater role in 

review and approval of plans, but the 

proposed Reliability Standards reflect 

primarily a continuation of existing 

system restoration requirements 

currently applicable to reliability 

coordinators, transmission operators 

and generation operators. 

52. Based on available information 

regarding NERC’s compliance registry, 

and our best assessment of the 

application of the proposed Reliability 

Standards, approximately 1,110 entities 

will be responsible for compliance with 

proposed Reliability Standards EOP– 

005–2 and EOP–006–2, of which 

approximately 678 are transmission 

owners and distribution providers not 

already subject to the existing system 

restoration Reliability Standards. Of the 

678 transmission owners and 

distribution providers, only that subset 

whose field switching personnel are 

identified in the restoration plan as 

having unique tasks will be subject to a 

new requirement under the proposed 

standards, i.e., providing two hours of 

system restoration training every two 

calendar years to such personnel. The 

Commission estimates that this 

requirement will impose a cost of 

perhaps $1,056 per year on transmission 

owners and distribution providers, (and 

indeed for some entities there will be 

only de minimis additional cost because 

field personnel are already being trained 

in restoration tasks) and therefore 

should not present significant operating 

costs. 

53. Based on this understanding, the 

Commission certifies that this rule will 

not have a significant economic impact 

on a substantial number of small 

entities. Accordingly, no regulatory 

flexibility analysis is required. 

VI. Document Availability 

54. In addition to publishing the full 

text of this document in the Federal 

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 p.m. Eastern time) at 888 First 

Street, NE., Room 2A, Washington, DC 

20426. 

55. 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. 

56. User assistance is available for 

eLibrary and the FERC’s Web site during 

normal business hours from FERC 

Online Support at 202–502–6652 (toll 

free at 1–866–208–3676) or e-mail at 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. E-mail the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

VII. Effective Date and Congressional 

Notification 

57. These regulations are effective 

May 23, 2011. The Commission notes 

that although the determinations made 

in this Final Rule are effective May 23, 

2011 in those jurisdictions where 

regulatory approval is required, 

Reliability Standard EOP–001–1 will 

not become effective until the first day 

of the first calendar quarter three 

months after regulatory approval is 

obtained, and EOP–005–2 and EOP– 

006–2 approved in this Final Rule will 

not become effective until 24 months 


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after the first day of the first quarter 

after applicable regulatory approval. 

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. 

By the Commission. 

Kimberly D. Bose, 

Secretary. 

[FR Doc. 2011–6739 Filed 3–22–11; 8:45 am] 

BILLING CODE 6717–01–P 

DELAWARE RIVER BASIN 

COMMISSION 

18 CFR Part 410 

Amendments to the Water Quality 

Regulations, Water Code and 

Comprehensive Plan To Update Water 

Quality Criteria for Toxic Pollutants in 

the Delaware Estuary and Extend 

These Criteria to Delaware Bay 

AGENCY: Delaware River Basin 

Commission. 

ACTION: Final rule. 

SUMMARY: By Resolution No. 2010–13 on 

December 8, 2010, the Delaware River 

Basin Commission (DRBC or 

‘‘Commission’’) approved amendments 

to its Water Quality Regulations, Water 

Code and Comprehensive Plan to 

update the Commission’s human health 

and aquatic life stream quality 

objectives (also called water quality 

criteria) for toxic pollutants in the 

Delaware Estuary (DRBC Water Quality 

Zones 2 through 5) and extended 

application of the criteria to Delaware 

Bay (DRBC Water Quality Zone 6). 

DATES: Effective Date: March 23, 2011. 

The incorporation by reference of the 

publications listed in this rule is 

approved by the Director of the Federal 

Register as of March 23, 2011. 

FOR FURTHER INFORMATION CONTACT: For 

questions about the technical basis for 

the rule, please contact Dr. Ronald 

MacGillivray at 609–477–7252. 

SUPPLEMENTARY INFORMATION: The 

Delaware River Basin Commission is a 

federal-state regional agency charged 

with managing the water resources of 

the Delaware River Basin without regard 

to political boundaries. Its members are 

the governors of the four basin states— 

Delaware, New Jersey, New York, and 

Pennsylvania—and the North Atlantic 

Division Commander of the U.S. Army 

Corps of Engineers, representing the 

Federal government. 

Notice of the proposed amendments 

appeared in the Federal Register (75 FR 

41106) on July 15, 2010 as well as in the 

Delaware Register of Regulations (14 DE 

Reg. 70–83 (08/01/2010)) on August 1, 

2010, the New Jersey Register (42 N.J.R. 

1701(a)) on August 4, 2010, the New 

York State Register (p. 6) on July 21, 

2010 and the Pennsylvania Bulletin (40 

Pa. B. 4208) on July 31, 2010. A public 

hearing was held on September 23, 2010 

and written comments were accepted 

through October 1, 2010. The 

commission received two written 

submissions and no oral testimony on 

the proposed changes. The Commission 

made minor revisions to the proposed 

amendments in response to the 

comments received. A comment and 

response document setting forth the 

Commission’s responses and revisions 

in detail was approved by the 

Commission simultaneously with 

adoption of the final rule. 

Resolution No. 2010–13, the text of 

the final rule, a copy of the comment 

and response document, and a basis and 

background document published 

simultaneously with the proposed rule 

are available on the Commission’s Web 

site, at http://www.state.nj.us/drbc/ 

toxics_info.htm. 

List of Subjects in 18 CFR Part 410 

Incorporation by reference, Water 

audit, Water pollution control, Water 

reservoirs, Water supply, Watersheds. 

For the reasons set forth in the 

preamble, the Delaware River Basin 

Commission amends part 410 of title 18 

of the Code of Federal Regulations as 

follows: 

PART 410—BASIN REGULATIONS; 

WATER CODE AND ADMINISTRATIVE 

MANUAL—PART III WATER QUALITY 

REGULATIONS 

■ 1. The authority citation for part 410 

continues to read as follows: 

Authority: Delaware River Basin Compact, 

75 Stat. 688. 

■ 2. Amend § 410.1 by revising the first 

sentence of paragraph (c) to read as 

follows: 

§ 410.1 Basin regulations—Water Code 

and Administrative Manual—Part III Water 

Quality Regulations. 

* * * * * 

(c) Work, services, activities and 

facilities affecting the conservation, 

utilization, control, development or 

management of water resources within 

the Delaware River Basin are subject to 

regulations contained within the 

Delaware River Basin Water Code with 

Amendments Through December 8, 

2010 and the Administrative Manual— 

Part III Water Quality Regulations with 

Amendments Through December 8, 

2010. * * * 

Dated: March 15, 2011. 

Pamela M. Bush, 

Commission Secretary. 

[FR Doc. 2011–6636 Filed 3–22–11; 8:45 am] 

BILLING CODE 6360–01–P 

DEPARTMENT OF HEALTH AND 

HUMAN SERVICES 

Food and Drug Administration 

21 CFR Part 172 

[Docket No. FDA–2002–F–0198] (formerly 

Docket No. 2002F–0316) 

Food Additives Permitted for Direct 

Addition to Food for Human 

Consumption; Bacteriophage 

Preparation 

AGENCY: Food and Drug Administration, 

HHS. 

ACTION: Final rule; response to 

objections and denial of requests for a 

hearing and stay of effective date. 

SUMMARY: The Food and Drug 

Administration (FDA) is responding to 

objections and is denying requests that 

it has received for a hearing on the final 

rule that amended the food additive 

regulations to provide for the use of a 

bacteriophage preparation as an 

antimicrobial agent against Listeria 

monocytogenes on ready-to-eat (RTE) 

meat and poultry products. After 

reviewing the objections to the final rule 

and the requests for a hearing, the 

Agency has concluded that the 

objections do not raise issues of material 

fact that justify a hearing or otherwise 

provide a basis for revoking the 

amendment to the regulation. FDA also 

is denying the request for a stay of the 

effective date of the final rule. 

DATES: Effective date of the final rule 

published in the Federal Register of 

August 18, 2006 (71 FR 47729) 

confirmed: August 18, 2006. 

FOR FURTHER INFORMATION CONTACT: 

James C. Wallwork, Center for Food 

Safety and Applied Nutrition (HFS– 

265), Food and Drug Administration, 

5100 Paint Branch Pkwy., College Park, 

MD 20740–3835, 301–436–1303. 

SUPPLEMENTARY INFORMATION: 

I. Introduction 

FDA published a notice in the Federal 

Register of July 22, 2002 (67 FR 47823), 

announcing the filing of food additive 

petition, FAP 2A4738, by Intralytix Inc., 

to amend the food additive regulations 

by providing for the safe use of a 


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