16240 Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 

(including all conditions and limitations 

stipulated in the exemption) will be 

taken to ensure safety. The FAA further 

stated that ‘‘operations authorized under 

these exemptions are specifically not air 

tour, sightseeing, or air carrier 

operations’’ and that the agency ‘‘in 

determining the public interest derived 

in any grant of exemption of this nature, 

will take into consideration the number 

of existing operational aircraft and 

petitioners available to provide the 

historic service to the public.’’ 

Consistent with the 2007 policy 

statement, the FAA has accommodated 

several industry requests to allow 

operation of more modern-day military 

jet aircraft (e.g., the McDonnell Douglas 

F–4 Phantom and the McDonnellDouglas A–4 Skyhawk) under the LHFE 

policy. To ensure safety, there are over 

45 conditions and limitations the 

exemption holder must comply with in 

order to operate under the provisions of 

the exemption. The FAA has found, 

however, that operators have sometimes 

misinterpreted these conditions and 

limitations as permitting operations that 

the FAA did not contemplate or intend. 

FAA Policy 

The evolution of LHFE operations in 

the private sector, along with 

availability of newer and more capable 

former military aircraft, has raised 

public safety and public policy concerns 

that the FAA needs to assess. 

Accordingly, the FAA is placing a 

moratorium on the issuance of any new 

LHFE exemptions, including addition of 

new aircraft to current exemptions. 

Current LHFE exemption holders can 

continue to operate under their current 

exemption. If the exemption is due to 

expire during the moratorium, the FAA 

will accept and process petitions to 

extend current exemptions in 

accordance with the established 

regulatory exemption process. If a 

change is required (i.e. removal of an 

aircraft) the FAA will accept these 

changes in accordance with the 

regulatory processes. Additionally, 

during the moratorium, as petitioners 

request extensions to their LHFE 

exemption, the FAA will add the 

following clarifying limitations to all 

LHFE exemptions to ensure consistent 

application of current LHFE policy: 1. 

Passengers are prohibited from 

manipulating the aircraft flight controls 

when the aircraft is operated under the 

LHFE exemption, and 2. No aerobatics 

may be performed in the aircraft while 

operating under the LHFE exemption. 

Finally, the FAA will begin its 

evaluation of the current LHFE 

exemption policies and practices, to 

include evaluation of safety to the 

paying members of the public who have 

an expectation of aircraft safety and who 

may not understand the inherent risks 

associated with such flight. The FAA 

expects to publish a new proposed 

LHFE policy for comment on or before 

September 30, 2012. 

Issued in Washington, DC, on March 15, 

2011. 

John W. McGraw, 

Acting Director, Flight Standards Service. 

[FR Doc. 2011–6712 Filed 3–22–11; 8:45 am] 

BILLING CODE 4910–13–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket No. RM10–15–000; Order No. 748] 

Mandatory Reliability Standards for 

Interconnection Reliability Operating 

Limits 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: Under section 215 of the 

Federal Power Act, the Federal Energy 

Regulatory Commission (Commission) 

approves three new Interconnection 

Reliability Operations and Coordination 

Reliability Standards and seven revised 

Reliability Standards related to 

Emergency Preparedness and 

Operations, Interconnection Reliability 

Operations and Coordination, and 

Transmission Operations. These 

Reliability Standards were submitted to 

the Commission for approval by the 

North American Electric Reliability 

Corporation (NERC), which the 

Commission has certified as the Electric 

Reliability Organization responsible for 

developing and enforcing mandatory 

Reliability Standards. The Reliability 

Standards were designed to prevent 

instability, uncontrolled separation, or 

cascading outages that adversely impact 

the reliability of the interconnection by 

ensuring that the reliability coordinator 

has the data necessary to assess its 

reliability coordinator area during the 

operations horizon and that it takes 

prompt action to prevent or mitigate 

instances of exceeding Interconnection 

Reliability. 

Operating Limits. The Commission 

also approves the addition of two new 

terms to the NERC Glossary of Terms. 

In addition, the Commission approves 

NERC’s proposed revisions to Reliability 

Standards EOP–001–1, IRO–002–2, 

IRO–004–2, IRO–005–3, TOP–003–1, 

TOP–005–2, and TOP–006–2, which 

remove requirements for the reliability 

coordinator to monitor and analyze 

system operating limits other than 

interconnection reliability operating 

limits. 

DATES: Effective Date: This Rule will 

become effective May 23, 2011. 

FOR FURTHER INFORMATION CONTACT: 

Darrell Piatt (Technical Information), 

Office of Electric Reliability, Division of 

Reliability Standards, Federal Energy 

Regulatory Commission, 888 First 

Street, NE., Washington, DC 20426. 

Telephone: (202) 502–6687. 

A. Cory Lankford (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426. 

Telephone: (202) 502–6711. 

William Edwards (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426. 

Telephone: (202) 502–6669. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Paragraph 

Nos. 

I. Background ............................................................................................................................................................................................ 3 

A. Mandatory Reliability Standards .......................................................................................................................................... 3 

B. Order No. 693 Directives ...................................................................................................................................................... 4 

C. NERC Petition ........................................................................................................................................................................ 7 

1. IRO–008–1 ................................................................................................................................................................ 11 

2. IRO–009–1 ................................................................................................................................................................ 15 

3. IRO–010–1a .............................................................................................................................................................. 16 

D. Notice of Proposed Rulemaking ........................................................................................................................................... 18 

II. Discussion ............................................................................................................................................................................................ 21 

A. Division of Responsibilities for SOLs and IROLs ............................................................................................................... 22 


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1 16 U.S.C. 824o (2006). 

2North American Electric Reliability Corp., 116 

FERC ¶ 61,062, order on reh’g & compliance, 117 

FERC ¶ 61,126 (2006), aff’d sub nom. Alcoa, Inc. v. 

FERC, 564 F.3d 1342 (DC Cir. 2009). 

3NERC defines IROLs as the value (such as MW, 

MVar, Amperes, Frequency or Volts) derived from, 

or a subset of the SOLs, which if exceeded, could 

expose a widespread area of the bulk electric 

system to instability, uncontrolled separation, or 

cascading outages. See NERC Glossary, available at 

http://www.nerc.com/docs/standards/rs/ 

Glossary_of_Terms_2010April20.pdf. 

4NERC defines SOLs as the value (such as MW, 

MVar, Amperes, Frequency or Volts) that satisfies 

the most limiting of the prescribed operating 

criteria for a specific system configuration to ensure 

operation within acceptable reliability criteria. Id. 

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

4, 2007), FERC Stats. & Regs. ¶ 31,242, order on 

reh’g, Order No. 693–A, 120 FERC ¶ 61,053 (2007). 

6Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 896. 

7 Id. P 908. 

8 Id. P 914. 

9 Id. P 935. NERC has subsequently replaced 

Levels of Non-Compliance with Violation Severity 

Continued 

Paragraph 

Nos. 

1. Continued Analysis of SOLs by Reliability Coordinators ..................................................................................... 26 

2. Documented Methodology to Identify System Operating Limit Information ...................................................... 33 

3. Current Practices for the Prevention and Mitigation of SOLs and IROLs and the Monitoring Capability of 

the Reliability Coordinator ...................................................................................................................................... 34 

4. Reliability Coordinator’s Procedures for Selecting the SOLs for Evaluation by the Interchange Distribution 

Calculator .................................................................................................................................................................. 37 

5. Current Functional Model ....................................................................................................................................... 38 

B. Operational Analyses and Real-time Assessments .............................................................................................................. 45 

C. Reliability Coordinator Actions to Operate Within IROLs ................................................................................................. 52 

D. IRO–010–1a ............................................................................................................................................................................ 56 

E. Violation Severity Levels and Violation Risk Factors ......................................................................................................... 64 

III. Information Collection Statement ...................................................................................................................................................... 73 

IV. Environmental Analysis ..................................................................................................................................................................... 78 

V. Regulatory Flexibility Act ................................................................................................................................................................... 79 

VI. Document Availability ....................................................................................................................................................................... 80 

VII. Effective Date and Congressional Notification ................................................................................................................................ 83 

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 Federal Energy 

Regulatory Commission (Commission) 

approves three new Interconnection 

Reliability Operations and Coordination 

(IRO) Reliability Standards and seven 

revised Reliability Standards related to 

Emergency Preparedness and 

Operations (EOP), IRO, and 

Transmission Operations (TOP). The 

proposed Reliability Standards were 

submitted to the Commission for 

approval by the North American Electric 

Reliability Corporation (NERC), which 

the Commission has certified as the 

Electric Reliability Organization (ERO) 

responsible for developing and 

enforcing mandatory Reliability 

Standards.2 These Reliability Standards 

were designed to prevent instability, 

uncontrolled separation, or cascading 

outages that adversely impact the 

reliability of the interconnection by 

ensuring that the reliability coordinator 

has the data necessary to assess its 

reliability coordinator area during the 

operations horizon and that it takes 

prompt action to prevent or mitigate 

instances of exceeding Interconnection 

Reliability Operating Limits (IROL).3

The Commission also approves the 

addition of two new terms to the NERC 

Glossary of Terms (NERC Glossary). In 

addition, the Commission approves 

NERC’s proposed revisions to Reliability 

Standards EOP–001–1, IRO–002–2, 

IRO–004–2, IRO–005–3, TOP–003–1, 

TOP–005–2, and TOP–006–2, which 

remove requirements for the reliability 

coordinator to monitor and analyze 

system operating limits (SOL) 4 other 

than IROLs. 

2. In addition, the Commission asks 

the ERO to evaluate certain issues 

through ongoing standards development 

and working group projects and to 

develop appropriate revisions as 

necessary. These issues regard the scope 

of the reliability coordinator’s 

responsibility under these and other 

IRO Reliability Standards. In particular, 

the Commission identifies, based on the 

comments received, certain issues 

regarding the delineation of the 

responsibility of the reliability 

coordinator to analyze, monitor and 

communicate to other operating entities 

the class of SOLs identified as ‘‘gridimpactive’’ SOLs by NERC. 

I. Background 

A. Mandatory Reliability Standards 

3. Section 215 of the FPA requires a 

Commission-certified ERO to develop 

mandatory and enforceable Reliability 

Standards, which are subject to 

Commission review and approval. Once 

approved, the Reliability Standards are 

enforced by the ERO, subject to 

Commission oversight, or by the 

Commission independently. 

B. Order No. 693 Directives 

4. On March 16, 2007, the 

Commission issued Order No. 693, 

approving 83 of the 107 initial 

Reliability Standards filed by NERC, 

including the currently-effective IRO 

Reliability Standards.5 Under section 

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

directed NERC to develop modifications 

to the IRO Reliability Standards to 

address certain issues identified by the 

Commission. 

5. With respect to IRO–001–1, the 

Commission directed the ERO to 

develop modifications to eliminate the 

regional reliability organization as an 

applicable entity.6 The Commission also 

directed the ERO to modify IRO–002–1 

to require a minimum set of capabilities 

that must be made available to the 

reliability coordinator to ensure that a 

reliability coordinator has the 

capabilities it needs to perform its 

functions.7 With respect to IRO–003–2, 

the Commission directed the ERO to 

develop a modification to create criteria 

to define the term ‘‘critical facilities’’ in 

a reliability coordinator’s area and its 

adjacent systems.8 The Commission also 

directed the ERO to modify IRO–004–1 

to require the next-day analysis to 

identify control actions that can be 

implemented and effective within 30 

minutes after a contingency. In addition, 

the Commission directed the ERO to 

consider adding Measures and Levels of 

Non-Compliance to Reliability 

Standards IRO–004–1 and IRO–005–1 

that are commensurate with the 

magnitude, duration, frequency and 

causes of the violations and whether 

these occur during normal or 

contingency conditions.9


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Levels. See Order on Violation Severity Levels 

Proposed by the Electric Reliability Organization, 

123 FERC ¶ 61,284 (Violation Severity Level Order), 

order on reh’g, 125 FERC ¶ 61,212 (2008). 

10 Id. P 951. 

11NERC, Compliance Filing, Docket No. RM06– 

16–006 (filed Oct. 31, 2008). 

12NERC, Compliance Filing, Docket No. RM06– 

16–006 (filed Feb. 8, 2009). 

13North American Electric Reliability Corp., Dec. 

31, 2009 Petition for Approval of Proposed New 

and Revised Reliability Standards for Operating 

Within Interconnection Operating Limits. 

14The term ‘‘Wide-Area’’ is defined in the NERC 

Glossary, approved by the Commission. As defined, 

Wide-Area includes not only the reliability 

coordinators’ area, but also critical flow and status 

information from adjacent reliability coordinator 

areas as determined by detailed system studies to 

allow the calculation of IROLs. See NERC Glossary 

available at http://www.nerc.com/docs/standards/ 

rs/Glossary_of_Terms_2010April20.pdf. 

15Concurrent with its Petition in this Docket, 

NERC filed a petition in Docket No. RM10–16–000 

seeking approval of certain Emergency 

Preparedness and Operations Reliability Standards. 

NERC, Petition for Approval of Three Emergency 

Preparedness and Operations Reliability Standards, 

Docket No. RM10–16–000 (filed Dec. 31, 2009). As 

part of its Petition in RM10–16–000, NERC 

proposed to retire Requirement R3.4 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. 

16NERC, Reliability Functional Model, version 5, 

at 30 (Dec. 2009), available at http://www.nerc.com/ 

files/Functional_Model_V5_Final_2009Dec1.pdf 

(NERC Functional Model). 

17 In its comments, NERC cites specific tasks 

outlined in the Functional Model for the respective 

duties of the reliability coordinator and 

transmission operator with respect to SOLs and 

IROLs. NERC Comments at 14. 

18NERC Petition at 77. 

19 Id. at 78. 

20 Id. at 7–9. 

21 Id. at 8. 

22 Id. at 9. 

23NERC Reliability Standard FAC–011–1, 

Requirement R3. 

6. The Commission also directed the 

ERO to conduct a survey on IROL 

practices and actual operating 

experiences by requiring reliability 

coordinators to report any violations of 

IROLs, their causes, the date and time, 

the durations and magnitudes in which 

actual operations exceed IROLs to the 

ERO on a monthly basis for one year 

beginning two months after the effective 

date of Order No. 693.10 On October 31, 

2008, NERC filed the results of its yearlong survey with the Commission.11 On 

February 8, 2009, NERC supplemented 

those results in a second filing.12

C. NERC Petition 

7. On December 31, 2009, NERC 

submitted a petition to the Commission 

(NERC Petition) 13 seeking approval of 

proposed Reliability Standards IRO– 

008–1, IRO–009–1, and IRO–010–1a. 

Under these Reliability Standards, 

reliability coordinators must analyze 

and monitor IROLs within their WideArea 14 to prevent instability, 

uncontrolled separation, or cascading 

outages that adversely impact the 

reliability of the interconnection. These 

Reliability Standards do not require the 

reliability coordinator to analyze and 

monitor SOLs other than IROLs or to 

take preventive action to avoid or 

mitigate SOL violations within their 

reliability coordinator area. In 

developing the proposed IRO Reliability 

Standards, NERC determined that it was 

necessary to retire or modify certain 

requirements from several existing 

Reliability Standards. Therefore, NERC 

proposed revisions to Reliability 

Standards EOP–001–1,15 IRO–002–2, 

IRO–004–2, IRO–005–3, TOP–003–1, 

TOP–005–2, and TOP–006–2, which 

remove requirements for the reliability 

coordinator to monitor and analyze 

SOLs other than IROLs. NERC also 

requests approval of new definitions 

‘‘Operational Planning Analysis’’ and 

‘‘Real-time Assessment.’’ 

8. These IRO Reliability Standards 

together with the proposed revisions to 

existing Reliability Standards divide 

responsibility for SOLs and IROLs 

between reliability coordinators and 

transmission operators according to the 

Functional Model.16 In its Petition, 

NERC explains that having two entities 

with the same primary responsibility is 

not supported by the Functional 

Model.17 However, NERC notes that 

these IRO Reliability Standards should 

not imply that the reliability coordinator 

will not look at its future operations 

with respect to specific SOLs.18 NERC 

states that the reliability coordinator 

must look at its future operations with 

respect to specific SOLs to ensure that 

their transmission operators are taking 

actions at appropriate times, but the 

primary responsibility for SOLs rests 

with the transmission operators. 

9. NERC explains that, under the new 

IRO Reliability Standards, the reliability 

coordinator retains overall visibility of 

all operations within its Wide-Area 

view, including some SOLs, although 

the transmission operator is primarily 

responsible for actions related to 

SOLs.19 NERC states that the IRO 

Reliability Standards were developed in 

support of the authority and assignment 

of tasks in the Functional Model.20

NERC explains that under the 

Functional Model, while reliability 

coordinators will assign their 

transmission operators tasks associated 

with IROLs, the reliability coordinator 

has ultimate responsibility for these 

tasks, and the reliability coordinator is 

sanctioned if these tasks are not 

performed as required by the Reliability 

Standards.21

10. NERC further explains that, in a 

similar fashion, the Functional Model 

assigns responsibility for SOLs that are 

not IROLs to the transmission operator. 

But, NERC states, this too is a shared 

responsibility.22 NERC states that, 

where the Transmission Operator has 

primary responsibility for developing 

the SOLs within its transmission 

operator area, the transmission operator 

may request the assistance of its 

reliability coordinator in developing 

these SOLs. In addition, NERC points 

out that reliability coordinators are 

responsible for ensuring that 

transmission operators develop SOLs for 

its reliability coordinator area in 

accordance with a methodology 

developed by the reliability 

coordinator.23 NERC states that the 

transmission operator must share its 

SOLs with its reliability coordinator, 

and the reliability coordinator must 

share any SOLs it develops with its 

transmission operator. NERC also states 

that the reliability coordinator monitors 

the status of some, but not all, SOLs. 

1. IRO–008–1 

11. Reliability Standard IRO–008–1 

has the stated purpose of preventing 

instability, uncontrolled separation, or 

cascading outages that adversely impact 

the reliability of the interconnection by 

ensuring that the bulk electric system is 

assessed during the operations horizon. 

The proposed Reliability Standard 

applies to reliability coordinators. IRO– 

008–1 requires the reliability 

coordinator to use analyses and 

assessments as methods of achieving the 

stated goal. The Reliability Standard 

requires analysis of the reliability 

coordinator’s Wide-Area ahead of time 

and during real-time. It also requires 

communication with the entities that 

need to take specific operational actions 

based on the analyses and assessments. 

12. Reliability Standard IRO–008–1 

contains three requirements. 

Requirement R1 requires each reliability 

coordinator to perform an Operational 

Planning Analysis to assess whether the 

planned operations for the next day 

within its Wide-Area will exceed any of 

its IROLs during anticipated normal and 

contingency event conditions. 

Requirement R2 requires the reliability 

coordinator to perform a Real-Time 

Assessment at least once every 30 

minutes to determine if its Wide Area is 

exceeding any IROLs or is expected to 

exceed any IROLs. Requirement R3 

requires a reliability coordinator to 

share the results of an Operational 


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24Because the interpretation for IRO–010–1 was 

completed before the filing of IRO–010–1, NERC 

requests Commission approval of IRO–010–1a, 

which includes the standard as interpreted. 

25The requirements in the standard are 

specifically applicable to the following functional 

entities: (1) Reliability coordinator[s]; (2) balancing 

authority; (3) generator owner; (4) generator 

operator; (5) interchange authority; (6) load-serving 

entity; (7) transmission operator; and (8) 

transmission owner. 

26NERC Petition at 77. 

27NERC identifies this as ‘‘Project 2007–03: Realtime Operations,’’ available at http:// 

www.nerc.com/filez/standards/Realtime_Operations_Project_2007–03.html. 

Planning Analysis or Real-Time 

Assessment that indicates the need for 

specific operational actions to prevent 

or mitigate an instance of exceeding an 

IROL with those entities that are 

expected to take those actions. 

13. NERC also requests approval of 

two new terms that appear in IRO–008– 

1: ‘‘Operational Planning Analysis’’ and 

‘‘Real-time Assessment.’’ Operational 

Planning Analysis is defined as: 

An analysis of the expected system 

conditions for the next day’s operation. (That 

analysis may be performed either a day ahead 

or as much as 12 months ahead.) Expected 

system conditions include things such as 

load forecast(s), generation output levels, and 

known system constraints (transmission 

facility outages, generator outages, equipment 

limitations, etc.). 

NERC states that the definition was 

designed to provide greater specificity 

regarding the day-ahead study. 

14. The proposed term ‘‘Real-time 

Assessment’’ is defined as ‘‘[a]n 

examination of existing and expected 

system conditions, conducted by 

collecting and reviewing immediately 

available data.’’ NERC states that the 

purpose of the new term is to assure that 

the reliability coordinator is required to 

conduct a real-time assessment, 

including situations in which the 

reliability coordinator is operating 

without its primary analysis facilities 

and has implemented the work-around 

requirements of IRO–002–2, 

Requirement R8. 

2. IRO–009–1 

15. As proposed, Reliability Standard, 

IRO–009–1 is designed to prevent 

instability, uncontrolled separation, or 

cascading outages that adversely impact 

the reliability of the interconnection by 

‘‘ensuring prompt action to prevent or 

mitigate instances of exceeding 

[IROLs].’’ Proposed Reliability Standard 

IRO–009–1 applies only to reliability 

coordinators. 

3. IRO–010–1a 

16. NERC proposes the addition of a 

new Reliability Standard, IRO–010–1a 24

to the current suite of IRO Reliability 

Standards. IRO–010–1a is designed to 

prevent instability, uncontrolled 

separation, or cascading outages that 

adversely impact the reliability of the 

interconnection by mandating that the 

reliability coordinator have the data it 

needs to monitor and assess the 

operation of its reliability coordinator 

area. 

17. The requirements in the 

Reliability Standard specify a formal 

request process for the reliability 

coordinator to explicitly identify the 

data and information it needs for 

reliability; and require the entities with 

the data to provide it as requested. The 

Reliability Standard applies to the 

reliability coordinator and to the other 

functional entities that must supply data 

to the reliability coordinator.25 This 

includes entities that have been 

identified as owners, users, or operators 

of the Bulk-Power System. 

D. Notice of Proposed Rulemaking 

18. On November 18, 2010, the 

Commission issued a Notice of 

Proposed Rulemaking (NOPR) 

proposing to approve Reliability 

Standards IRO–008–1, IRO–009–1, and 

IRO–010–1a; revised Reliability 

Standards EOP–001–1, IRO–002–2, 

IRO–004–2, IRO–005–3, TOP–003–1, 

TOP–005–2, and TOP–006–2; and the 

two new NERC Glossary terms. 

19. In the NOPR, the Commission 

agreed with NERC that it is appropriate 

to develop requirements for Reliability 

Standards that offer a clear division of 

responsibilities among reliability 

coordinators and transmission 

operators. In addition, the Commission 

sought ERO and public comment to 

ensure that the proposed Reliability 

Standards will not create a reliability 

gap by the inappropriate division of 

responsibilities for analyzing, 

monitoring and resolving SOLs and 

IROLs between transmission operators 

and reliability coordinators respectively. 

20. In response to the NOPR, NERC 

and a number of parties filed comments. 

PJM Interconnection L.L.C., ISO New 

England, New York Independent System 

Operator, Inc., California Independent 

System Operation Corporation and 

Southwest Power Pool submitted joint 

comments (Joint Commenters). The 

Edison Electric Institute (EEI), Midwest 

Independent Transmission System 

Operator, Inc. (Midwest ISO), and 

Western Electricity Coordinating 

Council (WECC) also submitted timely 

comments. American Electric Power 

Service Corp. (AEP) filed comments one 

day out-of-time. 

II. Discussion 

21. The Commission hereby adopts its 

NOPR proposals and approves new 

Reliability Standards IRO–008–1, IRO– 

009–1, and IRO–010–1a; revised 

Reliability Standards EOP–001–1, IRO– 

002–2, IRO–004–2, IRO–005–3, TOP– 

003–1, TOP–005–2, and TOP–006–2; 

and the two new NERC Glossary terms: 

‘‘Operational Planning Analysis’’ and 

‘‘Real-time Assessment.’’ In approving 

these Reliability Standards, the 

Commission concludes that they are 

just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. These Reliability 

Standards serve an important reliability 

purpose in seeking to prevent 

instability, uncontrolled separation, or 

cascading outages that adversely impact 

the reliability of the interconnection by 

ensuring that the reliability coordinator 

has the data necessary to assess its 

reliability coordinator area during the 

operations horizon and that it takes 

prompt action to prevent or mitigate 

instances of exceeding IROLs. Moreover, 

they clearly identify the entities to 

which they apply and contain clear and 

enforceable requirements. Commenters 

addressed many of the Commission 

concerns discussed in the NOPR and in 

some areas the ERO has indicated that 

it is continuing to study some issues 

related to the Commission concerns. 

The Commission encourages the ERO, 

applying its technical expertise, to 

continue such reviews and make any 

necessary changes to applicable 

Reliability Standards. 

A. Division of Responsibilities for SOLs 

and IROLs 

22. In the NOPR, the Commission 

sought comment on a number of issues 

related to NERC’s division of 

responsibilities for SOLs and IROLs 

between reliability coordinators and 

transmission operators. NERC 

acknowledges in its Petition that the 

transmission operator must develop and 

share its SOLs with its reliability 

coordinator, and the reliability 

coordinator must share any SOLs it 

develops with its transmission 

operator.26 NERC also states that it is 

currently working on a project to 

identify a subset of SOLs, other than 

IROLs, that the transmission operator 

and reliability coordinator must 

continuously analyze and monitor.27

Therefore, in the NOPR, the 

Commission sought comment on 

whether there is a need for reliability 

coordinators to continue to analyze, in 

addition to continuing to monitor and 

coordinate data on, SOLs other than 


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28Under NERC FAC–011–2, reliability 

coordinators must have a documented methodology 

for use in developing SOLs within its reliability 

coordinator area. 

29NERC Petition at 9. 

30NERC Petition at 10. 

31NERC Comments at 7. NERC does not offer a 

definition of the term ‘‘grid-impactive SOL,’’ but we 

understand it to mean an SOL that the reliability 

coordinator monitor so that it does not develop into 

an IROL. 

IROLs.28 The Commission also sought 

comment on whether the reliability 

coordinator should have a documented 

methodology for identifying the SOL 

information it needs to fulfill its 

responsibilities for day-ahead analysis, 

monitoring and real-time assessments, 

and operational control within the 

reliability coordinator’s area. 

23. The Commission requested 

information from NERC, reliability 

coordinators, and other interested 

entities on the current practices of 

reliability coordinators and 

transmission operators with respect to 

coordinating operational responsibilities 

for monitoring, day ahead and real-time 

assessments. The Commission also 

asked for comments on Bulk-Power 

System operations related to SOLs and 

IROLs, on the practical division of 

responsibilities for preventing and 

mitigating SOL and IROL violations, 

and the monitoring capabilities of the 

reliability coordinator with respect to 

IROLs as well as other SOLs. 

Additionally, the Commission asked 

whether a reliability coordinator can 

provide an accurate assessment of the 

Bulk-Power System to its transmission 

operators on a Wide-Area basis, without 

evaluating: (1) The operating 

environment of SOLs that will impact 

the transmission operators within the 

reliability coordinator’s areas; (2) SOLs 

that have the potential to become IROLs; 

and, (3) the existing IROLs within the 

reliability coordinator area. The 

Commission further sought comment as 

to whether a transmission operator can 

provide reliable operating assessments 

or make reliable operating instructions 

on an SOL that is on the border between 

two different transmission operator’s 

areas. The Commission also requested 

comment on whether the reliability 

coordinator should have responsibility 

to monitor certain SOLs other than 

IROLs, and whether such a 

responsibility would place an 

unreasonable burden on reliability 

coordinators. 

24. The Commission noted that IRO– 

006–4.1 requires the reliability 

coordinator to model SOLs and IROLs 

in the Interchange Distribution 

Calculator (IDC) to perform the 

Transmission Loading Relief 

procedures. We sought comment on 

how reliability coordinators in the 

Eastern Interconnection select the SOLs 

for evaluation in the IDC and the extent 

of any burden this has caused the 

reliability coordinator. 

25. Finally, the Commission also 

sought comments from NERC and the 

public as to how the current Functional 

Model represents the delineation of 

assessment and operating 

responsibilities between the reliability 

coordinator and transmission operator 

with respect to SOLs and IROLs. 

Comments 

1. Continued Analysis of SOLs by 

Reliability Coordinators 

26. NERC states in its comments, that 

the proposed IRO Reliability Standards 

appropriately distinguish which entity 

has primary responsibility for SOLs. 

Further, Bulk-Power System reliability 

practices assign responsibilities for 

analyzing and resolving conditions to 

the entities closest to it, so that the 

entity with the closest eye to the 

condition can quickly assess and resolve 

it. NERC asserts that it is appropriate for 

transmission operators to maintain 

primary responsibility for SOLs, and for 

reliability coordinators to maintain 

primary responsibility for IROLs. NERC 

also explains that, while SOLs are 

typically associated with the prevention 

of facility damage or the accelerated 

degradation of equipment life, only a 

subset of SOLs are used to analyze and 

monitor local area reliability and, 

therefore, the proposed IRO standards 

are silent on the reliability coordinator’s 

responsibility with respect to SOLs. 

27. NERC notes in its Petition, that the 

proposed Reliability Standards ‘‘should 

not imply that the Reliability 

Coordinator will not look at its future 

operations with respect to specific 

SOLs.’’ 29 NERC also states that ‘‘[t]he 

Reliability Coordinator retains the 

overall visibility of all operations within 

its Wide-Area view, including some 

SOLs, although the transmission 

operator is primarily responsible for 

actions related to SOLs.’’ 30 NERC also 

notes that the reliability coordinator can 

monitor the transmission operator’s 

actions to resolve SOLs and provides, as 

an example, that the reliability 

coordinator can study real-time 

operating trends to help determine 

whether an asset is trending toward a 

‘‘grid-impactive SOL.’’ 31

28. In its comments, NERC provides 

the results of a survey conducted in 

response to the NOPR in which each of 

the nine reliability coordinators in the 

Eastern Interconnection responded that, 

for SOLs that it monitors, the SOLs were 

developed in a coordinated fashion with 

the transmission operators in its area. 

The survey responses did not suggest 

that any transmission operator withheld 

important SOL information from 

reliability coordinators, nor did any 

reliability coordinator indicate that 

transmission operators were not willing 

to work with the reliability coordinators 

in monitoring SOLs for Bulk-Power 

System reliability. NERC contends that 

this survey demonstrates that current 

operating practices are effective to 

ensure that reliability coordinators are 

able to obtain sufficient information 

from transmission operators in order to 

analyze and monitor certain SOLs other 

than IROLs. 

29. NERC also notes that, since the 

completion of the proposed IRO 

standards, the industry has been 

working to improve the clarity of 

Reliability Standard requirements 

regarding the transmission operator’s 

primary responsibility for SOLs through 

the Real-time Operations Standard 

Drafting Team (Project 2007–03). For 

example, NERC explains that the 

Standard Drafting Team has proposed to 

add a requirement to TOP–001–2 that 

would require each transmission 

operator to inform its reliability 

coordinator of all SOLs which, while 

not IROLs, have been identified by the 

transmission operator as supporting its 

local area reliability based on its 

assessment of its Operational Planning 

Analysis. NERC states that, by using 

tools that properly model Wide-Area 

conditions, the reliability coordinators 

are able to identify and help resolve 

lower-level issues that may not 

explicitly be included in the reliability 

coordinator modeling capabilities. EEI 

supports NERC’s comments to the 

NOPR and believes that the Commission 

should encourage the NERC reliability 

coordinators working group to engage 

these issues with NERC stakeholders, 

especially the NERC Planning and 

Operating Committees. 

30. The Joint Commenters support the 

proposed primary division of 

responsibilities for SOLs and IROLs 

between reliability coordinators and 

transmission operators. They contend, 

though, that the proposed division 

should not be interpreted as implying 

that a reliability coordinator should not 

monitor any SOLs. The Joint 

Commenters further contend that it was 

not intended that the proposed 

Reliability Standards would remove all 

responsibility for SOLs from the 

reliability coordinator, but to establish a 

clear distinction of responsibilities and 

authority. The Joint Commenters state 

that they would not support a formal 


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32See NERC Functional Model at 31, 37. 

requirement that would assign primary 

responsibility for analyzing and 

resolving SOLs to a reliability 

coordinator since the primary 

responsibility is correctly assigned to 

the transmission operator that is most 

familiar with their respective operating 

limits and local Bulk-Power System 

characteristics. 

31. Midwest ISO states that it is 

necessary for reliability coordinators to 

analyze, monitor, and coordinate some 

SOLs other than IROLs and that the 

Reliability Standards should reflect this 

best practice. Midwest ISO believes the 

Commission should encourage the 

efforts currently underway at NERC 

towards the development of Reliability 

Standards addressing the role of 

reliability coordinators with regard to 

analyzing SOLs, other than IROLs, that 

are important to the reliable operation of 

the Bulk-Power System. 

32. AEP states that it generally 

supports the proposed Reliability 

Standards but that it agrees with 

concerns raised by the Commission that 

if reliability coordinators are not 

monitoring other SOLs, there is a 

potential gap in monitoring for SOLs 

that have the potential to become IROLs. 

AEP argues that performing an annual 

IROL identification would be 

insufficient because it could miss some 

opportunities to identify these 

potentially new IROLs when they could 

be material. AEP asserts that, at a 

minimum, reliability coordinators 

should be required to be involved in 

SOLs that could border two different 

transmission operators’ areas to ensure 

the activities are appropriately 

coordinated. AEP states that reliability 

coordinators and transmission operators 

should develop this subset of SOLs 

through joint analysis, or agreement. 

AEP requests that the Commission 

direct NERC to develop a modification 

to proposed Reliability Standards EOP– 

001–1, IRO–002–2, IRO–004–2, IRO– 

005–3, TOP–003–1, TOP–005–2, and 

TOP–006–2, to require reliability 

coordinators to work together with 

transmission operators in developing 

and monitoring SOLs that border 

multiple transmission operators’ areas. 

2. Documented Methodology To Identify 

System Operating Limit Information 

33. NERC asserts that, because 

proposed Reliability Standard IRO–008– 

1 requires reliability coordinators to use 

tools to model transmission and 

generation assets based on ratings 

provided by asset owners, it is 

unnecessary to impose an additional 

requirement that the reliability 

coordinator have a documented 

methodology for identifying the SOL 

information it needs because the 

systems and controls in place already 

provide the information needed by the 

reliability coordinators. The Joint 

Commenters also believe that such a 

methodology is unnecessary because, in 

its defined role, a reliability coordinator 

already will have access to, and be 

provided with, the appropriate set of 

SOLs from the transmission operator. 

3. Current Practices for the Prevention 

and Mitigation of SOLs and IROLs and 

the Monitoring Capability of the 

Reliability Coordinator 

34. NERC states that current practices 

give the reliability coordinators the 

ability to provide assessments of the 

Bulk-Power System to their 

transmission operators on a Wide-Area 

basis. NERC believes it is unnecessary to 

require reliability coordinators to have 

additional responsibility to monitor 

SOLs other than IROLs. NERC also notes 

that there are checks in place that allow 

the reliability coordinator to monitor 

SOLs that could turn into IROLs. As an 

example, NERC points out that IRO– 

010–1a requires reliability coordinators 

to conduct Operational Planning 

Analyses and Real-Time Assessments to 

identify any IROLs that may be 

exceeded. 

35. NERC states that the electric 

power industry is predicated on 

interdependencies. NERC describes the 

interdependency of transmission 

operators and reliability coordinators as 

enabling the reliability coordinator both 

to control IROLs and flows, and to be 

aware of local issues, giving the 

reliability coordinator the ability to 

monitor SOLs that may become IROLs 

within the reliability coordinators areas. 

NERC further explains that it is working 

on Project 2007–03—Real-Time 

Operations to develop proposed 

revisions to the TOP standards that 

require a transmission operator to 

perform Operational Planning Analyses 

for its transmission operator area. NERC 

states that Project 2007–03 is 

considering revisions to the Reliability 

Standards that would require 

observation of SOL limits in adjoining 

areas. 

36. The Joint Commenters state that 

the proposed IRO Reliability Standards 

hold reliability coordinators to the 

proper assessment of information 

required to provide accurate 

assessments on a Wide-Area basis. The 

Joint Commenters also caution that 

‘‘accurate assessments’’ do not equate to 

precise results and the Commission 

should refrain from mandating that 

reliability coordinators provide accurate 

assessments. 

4. Reliability Coordinator’s Procedures 

for Selecting the SOLs for Evaluation by 

the Interchange Distribution Calculator 

37. NERC states that reliability 

coordinators in the Eastern 

Interconnection select which SOLs to 

evaluate in the interchange distribution 

calculator based on information 

received from the transmission 

operators indicating that the 

transmission operator has a facility that 

is approaching or exceeding its SOL 

and/or IROL. NERC states that the 

interchange distribution calculator is a 

congestion management tool that helps 

the reliability coordinators deal with 

transmission constraints. In the survey 

conducted by NERC of reliability 

coordinators, one reliability coordinator 

responded that it publishes most of its 

information for use by any entity that 

may wish to use the information in its 

reliability assessments. Another 

reliability coordinator responded that it 

does not enter SOLs in its area into the 

interchange distribution calculator, but 

flowgates are entered into the 

interchange distribution calculator that 

may have SOLs or IROLs associated 

with them. Entering the flowgates 

allows an entity to determine if external 

schedules are impacting the flowgate. 

5. Current Functional Model 

38. NERC argues that Version 5 of the 

NERC Functional Model makes a clear 

distinction between the duties of the 

reliability coordinator and transmission 

operator with respect to SOLs and 

IROLs in certain task descriptions.32

Similarly, the Joint Commenters state 

that the latest NERC Functional Model 

divides reliability components and 

allocates them to ‘‘unique’’ baskets of 

tasks which include a fundamental 

reliability task to do Wide-Area analysis 

and another task for local analysis. 

Commission Determination 

39. As we stated in the NOPR, we 

believe that it is appropriate for 

Reliability Standards requirements to 

offer a clear division of responsibilities 

among reliability coordinators and 

transmission operators. The 

preponderance of comments to the 

NOPR supports Commission approval of 

the Reliability Standards as proposed by 

NERC, including the proposed division 

of responsibilities. For the reasons 

described below, we approve the 

division of responsibility for SOLs and 

IROLs among transmission operators 

and reliability coordinators as expressed 

in the proposed Reliability Standards. 

40. NERC and others suggest that 

these Reliability Standards are not 


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intended to remove all responsibility for 

the analysis and monitoring SOLs from 

the reliability coordinator. We agree. 

These Reliability Standards generally 

establish a clear distinction of primary 

responsibility for SOLs and IROLs 

between the transmission operator and 

reliability coordinator respectively. As 

NERC notes, however, the reliability 

coordinator will continue to have the 

ability and the responsibility to analyze 

and monitor SOLs that could turn into 

IROLs. For example, Requirements R5 

and R6 of Reliability Standard IRO– 

002–2 require the reliability coordinator 

to monitor the important elements that 

could be critical to SOLs and IROLs 

within the reliability coordinator’s area 

and surrounding reliability coordinator 

areas. In addition, the proposed IRO 

Reliability Standards require the 

reliability coordinator to conduct 

Operational Planning Analyses and 

Real-time Assessments of its reliability 

coordinator area. As NERC explained, 

the Operational Planning Analyses look 

at the expected system conditions and 

potential reliability impacts, with a 

focus on any impacts that affect the 

Wide-Area. Although a transmission 

operator lacks the tools to predict the 

impact on the surrounding transmission 

operator areas due to any changes in 

flow between inter-area facilities, a 

reliability coordinator addresses these 

facilities in its Wide-Area modeling 

capabilities. 

41. As the Commission noted in its 

NOPR, Reliability Standard IRO–002–2 

continues to require each reliability 

coordinator to monitor SOLs other than 

IROLs both within its reliability 

coordinator area and in surrounding 

reliability coordinator areas. 

Specifically, under Requirement R4 of 

IRO–002–2, each reliability coordinator 

must have detailed real-time monitoring 

capability of its reliability coordinator 

area and sufficient monitoring 

capability of its surrounding reliability 

coordinator areas to ensure that 

potential or actual SOL or IROL 

violations are identified and analyzed. 

In addition, under Requirement R5, 

each reliability coordinator must 

monitor bulk electric system elements 

such as generators, transmission lines, 

buses, transformers and breakers that 

could result in SOL or IROL violations 

within its reliability coordinator area. 

Further, as the Commission noted in the 

NOPR, the reliability coordinator must 

resolve potential or actual violations of 

SOL ratings by implementing a local or 

area-wide transmission loading relief 

procedure under Reliability Standard 

IRO–006–4.1. 

42. Nevertheless, as noted by NERC 

and other commenters, there exists a 

subset of ‘‘grid-impactive’’ SOLs other 

than IROLs that the Commission 

believes may warrant closer analysis by 

the reliability coordinator, in addition to 

the analysis being conducted by the 

transmission operator, that focuses on 

whether these particular ‘‘gridimpactive’’ SOLs could become IROLs. 

The Commission believes that there can 

be considerable benefit derived from 

some overlap in the responsibility for 

analyzing and monitoring these ‘‘gridimpactive’’ SOLs since, by definition, 

every IROL emanated from an SOL. 

While the proposed Reliability 

Standards continue to commit the 

reliability coordinator to the analysis 

and monitoring of SOLs that may 

become IROLs, a subset of SOLs, such 

as these ‘‘grid-impactive’’ SOLs, may 

deserve a more defined analysis and 

monitoring role on the part of the 

reliability coordinator. 

43. We acknowledge NERC’s and 

industry’s continuing efforts to improve 

the clarity of standard requirements 

regarding SOLs through the Real-time 

Operations Standard Drafting Team 

(Project 2007–03). We believe that the 

issues concerning the analysis and 

monitoring of ‘‘grid-impactive’’ SOLs 

that we note here can be raised and 

considered in this or other ongoing 

projects. NERC comments that it is 

working on Project 2007–03 to develop 

revisions to the TOP Reliability 

Standards that require transmission 

operators to perform operational 

planning analyses for their local areas. 

NERC also comments that this project is 

also considering revisions that would 

require that SOL limits in adjoining 

areas be observed. In addition, there are 

other open projects, such as Project 

2006–06—Reliability Coordination, 

which is analyzing appropriate 

reliability coordinator functions and 

responsibilities. In consideration of 

these ongoing efforts, we will not direct 

specific modifications to these 

Reliability Standards and, rather, accept 

NERC’s commitment to exercise its 

technical expertise to study these issues 

and develop appropriate revisions to 

applicable Standards as may be 

necessary. 

44. Because the study and monitoring 

of SOLs and IROLs is an issue at the 

very core of Bulk-Power System 

reliability, the Commission agrees with 

EEI that the NERC Reliability 

Coordinators Working Group should 

engage the issues raised in this 

proceeding with NERC stakeholders, 

including the NERC Planning and 

Operating committees, to determine 

whether a need exists to further refine 

the delineation of responsibilities 

between the reliability coordinator and 

transmission operator for analyzing a 

class of ‘‘grid-impactive’’ SOLs. 

Depending on the results of that review, 

we further encourage NERC, working 

through its standard development 

process, to develop appropriate 

modifications to these and any other 

related Reliability Standards as 

necessary. 

B. Operational Analyses and Real-time 

Assessments 

45. In the NOPR, the Commission 

sought comment on the prudence of 

using an Operational Planning Analysis 

up to twelve months old. The 

Commission asked whether this 

timeframe is reasonable or whether the 

timeframe should be shorter to ensure 

that the analysis is not outdated. In 

addition, the Commission sought 

comment on whether the definition 

should include measurable criteria to 

determine whether it is appropriate to 

use an existing analysis. 

46. Further, the Commission 

requested comments on the meaning of 

‘‘immediately available data’’ within the 

proposed definition of the NERC 

Glossary definition of Real-Time 

Assessment. The Commission proposed 

to direct NERC to modify the definition 

of ‘‘Real-time Assessment’’ to specify 

that the type of data to be relied upon 

by a reliability coordinator in 

conducting a Real-time Assessment 

must be based on adequate analysis 

capabilities such as state estimation, 

pre- and post-contingency analysis 

capabilities (thermal, stability, and 

voltage), and wide-area overview 

displays referenced in Requirement R6 

of IRO–002–2. 

Comments 

47. In response to the Commission’s 

questions regarding the use of an 

existing Operational Planning Analysis, 

NERC states that it is unlikely that a 

reliability coordinator would 

deliberately rely on an Operational 

Planning Analysis that does not reflect 

its expected system conditions. NERC 

asserts that a reliability coordinator will 

rely on a twelve-month old operational 

planning analysis only if system 

conditions have not changed over that 

time period. NERC states that the 

proposed definition of Operational 

Planning Analysis was developed, based 

on stakeholder comments, to apply not 

only to studies conducted for the day 

ahead, but also for future use in possibly 

developing requirements for seasonal 

studies. Thus, NERC explains, the 

definition includes the option of 

performing an Operational Planning 

Analysis up to twelve months ahead. 

NERC further explains that the 


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definition includes key elements that 

provide measurable criteria in assessing 

an entity’s Operational Planning 

Analysis. 

48. In response to the Commission’s 

questions regarding the proposed 

definition of Real-time Assessment, 

NERC and the Joint Commenters state 

that the industry is currently working 

towards consensus on the set of data 

and capabilities the reliability 

coordinators need to perform their tasks 

via the Real-time Reliability Monitoring 

and Analysis Capabilities Standards 

Development Team (Project 2009–02). 

Accordingly, NERC asks the 

Commission to refrain from directing 

modifications pending completion of 

the project. 

Commission Determination 

49. The Commission approves the 

definitions of ‘‘Operational Planning 

Analysis’’ and ‘‘Real-time Assessment’’ 

without modification. 

50. The Commission agrees with 

NERC that the reliability coordinator 

should rely on a twelve-month old 

Operational Planning Analysis study 

only if system conditions have not 

changed from those originally studied. 

Consistent with the views of NERC, we 

expect that reliability coordinators will 

rely on Operational Planning Analysis 

that reflect expected system conditions. 

Accordingly, we accept the definition as 

proposed. 

51. Similarly, we find it is 

unnecessary to direct NERC to modify 

the definition of ‘‘Real-time Assessment’’ 

to specify that the type of data to be 

relied upon by a reliability coordinator 

in conducting a Real-time Assessment 

as proposed in the NOPR. Instead, the 

Commission will allow industry to 

complete Project 2009–02, which is 

working towards consensus on the set of 

data and capabilities the reliability 

coordinators need to perform their tasks. 

We expect NERC to use its technical 

expertise to develop any modifications 

to the definition of Real-time 

Assessment as may be necessary as a 

result of this ongoing project. 

C. Reliability Coordinator Actions To 

Operate Within IROLs 

52. In the NOPR, the Commission 

sought comment on whether reliability 

coordinators should have action plans 

developed and implemented with 

respect to other SOLs apart from IROLs 

and if so, which SOLs. 

Comments 

53. NERC states that transmission 

operators already are responsible for 

developing action plans for preventing 

and/or mitigating conditions that cause 

facility ratings to be exceeded. NERC 

therefore contends that it would add 

confusion to the process to require both 

the reliability coordinator and 

transmission operator to develop action 

plans for every SOL. 

54. Similarly, WECC does not believe 

that reliability coordinators should be 

required to have action plans developed 

and implemented for SOLs apart from 

IROLs. WECC argues that requiring the 

reliability coordinator to second guess 

rather than defer to the more granular 

view and detailed view of the 

transmission operators or balancing 

authorities undermines and 

substantially changes the roles of each 

function without any foreseeable benefit 

to overall reliability. 

Commission Determination 

55. The Commission agrees with 

NERC that requiring both the reliability 

coordinator and transmission operator 

to develop action plans for every SOL 

may add confusion to the process. As a 

result, the Commission approves IRO– 

009–1, without modification. However, 

the Reliability Coordinator Working 

Group should further study this issue 

and determine if there is a need for 

reliability coordinators to have action 

plans developed and implemented with 

respect to certain grid-impactive SOLs. 

D. IRO–010–1a 

56. In the NOPR, the Commission 

expressed concern that Reliability 

Standard IRO–010–1a does not require 

reliability coordinators to specify a list 

of minimum data needed for reliable 

operation of the Bulk-Power System. 

The Commission, therefore, sought 

comment on whether a minimum list of 

data is necessary for the effective 

sharing of data between neighboring 

reliability coordinators and, if so, what 

data should be included. The 

Commission also sought comment on 

how compatibility of data between 

neighboring reliability coordinators can 

be assured without a list of minimum 

data in this proposed Reliability 

Standard. 

57. In its discussion of Reliability 

Standard TOP–003–1, the Commission 

noted that Requirement R3 of proposed 

Reliability Standard IRO–010–1a 

requires entities to provide data and 

information to the reliability 

coordinator in accordance with the 

reliability coordinator’s specifications. 

The Commission expressed concern that 

this requirement does not specify outage 

coordination data and, therefore, the 

reliability coordinator may not receive 

adequate outage coordination data to 

support the Operational Planning 

Analysis. Accordingly, the Commission 

sought comment on whether IRO–010– 

1a should specify necessary outage 

coordination data. 

Comments 

58. NERC, the Joint Commenters and 

Midwest ISO contend that requiring a 

minimum list of data is not necessary 

for the effective sharing of data between 

neighboring reliability coordinators. 

NERC argues that requiring a list of 

minimum data not only could impair an 

entity’s ability to provide the data to the 

reliability coordinator quickly, but 

could prevent a reliability coordinator 

from obtaining needed data quickly. 

NERC also notes that, during the 

development of the proposed Reliability 

Standard, the reliability coordinators 

that were polled indicated they already 

were receiving the data they needed 

without any issues and that the data and 

information they received varied from 

one reliability coordinator to another. 

The Joint Commenters argue that it is 

unnecessary to develop such a 

requirement because two interconnected 

parties can agree upon the appropriate 

type and level of data it needs from the 

other, taking into consideration their 

respective tools and capabilities. 

Midwest ISO argues that many 

reliability coordinators already have 

developed coordination agreements 

with their neighbors that identify the 

information necessary for effective data 

sharing. Midwest ISO contends that a 

generic list of minimum data could be 

inadequate to meet regional needs and 

could create conflicts with existing 

coordination agreements. Midwest ISO 

further contends that a minimum list 

could curb creativity and innovation as 

capabilities develop new uses for data. 

59. NERC and the Joint Commenters 

also urge the Commission to refrain 

from requiring NERC to modify IRO– 

010–1a to specify the necessary outage 

coordination data for all reliability 

coordinators. They contend that such an 

approach would not account for the 

significantly varying facilities located 

within the reliability coordinators’ area 

and allow for the flexibility to specify 

the data needed for its respective area. 

60. Reiterating comments it raised 

during the standard development 

process, WECC opposes the requirement 

in R1.2 that the parties reach mutual 

agreement with respect to the format of 

the data and information that the 

reliability coordinator receives. WECC 

argues that, due to the large number of 

entities that must provide data to the 

reliability coordinator, the requirement 

for mutually agreeable formats may 

cause the reliability coordinator to 

receive data in a multitude of diverse 

formats. WECC also believes that 


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33Facilities Design, Connections and 

Maintenance Reliability Standards, Order No. 705, 

121 FERC ¶ 61,296, at P 137 (2007). 

34 Violation Severity Level Order, 123 FERC 

¶ 61,284. 

35 Guideline 2 contains two sub-parts: (a) the 

single violation severity level assignment category 

for binary requirements should be consistent and 

(b) violation severity levels assignments should not 

contain ambiguous language. 

36 Violation Severity Level Order, 123 FERC 

¶ 61,284 at P 17. 

37North American Reliability Corporation, Filing 

of the North American Electric Reliability 

Corporation regarding the Assignment of Violation 

Risk Factors and Violation Severity Levels, Docket 

No. RR08–4–005 (filed May 5, 2010). 

38 Id. 

39NERC, Informational Filing Regarding the 

Assignment of Violation Risk Factors and Violation 

Severity Levels, Docket Nos. RM08–11–000, RR07– 

9–000, and RR07–10–000 (filed Aug. 10, 2009). 

requiring mutually agreeable data 

formats could delay the submission of 

data by a submitting entity until 

agreement can be reached via 

negotiation or dispute resolution. WECC 

argues that more than one party is 

involved in the formulation of an 

agreeable format yet only a reliability 

coordinator will be found noncompliant when the reliability 

coordinator and transmission operators 

or balancing authorities within the 

reliability coordinator area fail to reach 

an agreement over an acceptable format. 

Commission Determination 

61. The Commission agrees with 

commenters that it is unnecessary to 

direct NERC to develop a specific list of 

minimum data for the effective sharing 

of data between neighboring reliability 

coordinators under Reliability Standard 

IRO–010–1a. NERC and other entities 

confirm that reliability coordinators 

currently obtain necessary data without 

such a specific list. In addition, as 

commenters point out, a minimum list 

may conflict with coordination 

agreements currently in place which 

identify the information necessary for 

effective data sharing. With regard to the 

concern expressed in the NOPR 

regarding outage coordination data, we 

accept that reliability coordinators 

currently obtain necessary data. If, in 

the future, reliability coordinators are 

not able to obtain the necessary outage 

coordination data, we would ask NERC 

to consider whether a Reliability 

Standard should be developed for the 

reliability coordinators to obtain such 

data. 

62. In response to WECC’s concerns 

about the submission of data in 

mutually agreeable formats under 

Requirement R1.2, we do not believe 

any modification is necessary. As NERC 

states in its Petition, by specifying that 

the format must be mutually agreeable, 

the standard supports efficiency by 

precluding the submission of data that 

is in a format that cannot be used. We 

agree. NERC states that current data 

exchange formats are acceptable. 

Therefore, entities can continue to 

utilize existing agreements regarding 

data exchange. While disputes may arise 

in the future, the Reliability Standard 

does not dictate a specific dispute 

resolution process in the interpretation 

leaving reliability coordinators and 

other entities options for informal 

resolution of a dispute on the format of 

data and flexibility in choosing a 

dispute resolution process to reach an 

agreement. 

63. Accordingly, the Commission 

approves IRO–010–1a as submitted. 

E. Violation Severity Levels and 

Violation Risk Factors 

64. In the event of a violation of a 

Reliability Standard, NERC establishes 

the initial value range for the 

corresponding base penalty amount. To 

do so, NERC assigns a violation risk 

factor for each requirement of a 

Reliability Standard that relates to the 

expected or potential impact of a 

violation of the requirement on the 

reliability of the Bulk-Power System. In 

addition, NERC defines up to four 

violation severity levels—Lower, 

Moderate, High, and Severe—as 

measurements for the degree to which 

the requirement was violated in a 

specific circumstance. 

65. In Order No. 705, the Commission 

approved 63 of NERC’s 72 proposed 

violation risk factors for the version one 

FAC Reliability Standards and directed 

NERC to file violation severity level 

assignments before the version one FAC 

Reliability Standards become 

effective.33 Subsequently, NERC 

developed violation severity levels for 

each requirement of the Commissionapproved FAC Reliability Standards, as 

measurements for the degree to which 

the requirement was violated in a 

specific circumstance. 

66. On June 19, 2008, the Commission 

issued its Violation Severity Level Order 

approving the violation severity level 

assignments filed by NERC for the 83 

Reliability Standards approved in Order 

No. 693.34 In that order, the Commission 

offered four guidelines for evaluating 

the validity of violation severity levels, 

and ordered a number of reports and 

further compliance filing to bring the 

remainder of NERC’s violation severity 

levels into conformance with the 

Commission’s guidelines. The four 

guidelines are: (1) Violation severity 

level assignments should not have the 

unintended consequence of lowering 

the current level of compliance; (2) 

violation severity level assignments 

should ensure uniformity and 

consistency among all approved 

Reliability Standards in the 

determination of penalties; 35 (3) 

violation severity level assignments 

should be consistent with the 

corresponding requirement; and (4) 

violation severity level assignments 

should be based on a single violation, 

not a cumulative number of 

violations.36 The Commission found 

that these guidelines will provide a 

consistent and objective means for 

assessing, inter alia, the consistency, 

fairness and potential consequences of 

violation severity level assignments. 

The Commission noted that these 

guidelines were not intended to replace 

NERC’s own guidance classifications, 

but rather, to provide an additional level 

of analysis to determine the validity of 

violation severity level assignments. 

67. On August 10, 2009, NERC 

submitted an informational filing setting 

forth a summary of revised guidelines 

that NERC intends to use in determining 

the assignment of violation risk factors 

and violation severity levels for 

Reliability Standards. NERC states that 

these revised guidelines were consistent 

with Commission’s guidelines. On May 

5, 2010, NERC submitted the subject 

informational filing as a supplement to 

its pending March 5, 2010 Violation 

Severity Level Order compliance 

filing.37

NERC Proposal 

68. NERC proposes a complete set of 

violation severity levels and violation 

risk factors for proposed new Reliability 

Standards IRO–008–1, IRO–009–1, and 

IRO–010–1a. In addition, NERC 

proposes to apply the existing set of 

violation severity levels and violation 

risk factors assigned to the proposed 

modified requirements. 

69. NERC states that it developed the 

violation severity levels for the new IRO 

Reliability Standards before the 

Commission issued its June 19, 2008 

Order on violation severity levels.38

NERC also notes that the proposed 

violation severity levels were developed 

before NERC proposed a new 

methodology for assigning violation 

severity levels and violation risk 

factors.39 As a result, NERC states that 

some of the proposed violation severity 

levels do not comport with the 

Commission’s guidelines on violation 

severity levels and some do not comport 

with the NERC’s revised guidelines. 

NERC identified differences and 

committed to propose revisions to the 

violation severity levels. 


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Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 16249 

40North American Electric Reliability Corp., 123 

FERC ¶ 61,284 (2008), order on reh’g, 125 FERC 

¶ 61,212 (2008) (VSL Orders). 

41North American Electric Reliability 

Corporation, Docket No. RR08–4–005 (Jul. 6, 2010) 

(granting an extension of time for submitting this 

VSL compliance filing up to and including 

December 1, 2010). 

42See NERC, Compliance Filing, Docket No. 

RR08–4–006, at 2 n.6 (filed Dec. 1, 2010). 

43 44 U.S.C. 3507(d). 

44 5 CFR 1320.11. 

45Proposed Reliability Standard IRO–010–1a, 

Requirement R3. 

70. Separately from NERC’s Petition 

here, on March 5, 2010, NERC 

submitted the first of two VSL 

compliance filings (Filing 1) to the 

Commission’s VSL Orders,40 which 

contained the VSL assignments for the 

original set of 83 Reliability Standards 

approved by the Commission and NUC– 

001–2. In addition, NERC requested an 

extension for filing the remaining VSLs 

until the 3rd quarter of 2010. On July 6, 

2010, the Commission issued a Notice of 

Extension of Time up to and including 

December 1, 2010, for Filing 2.41 On 

December 1, 2010, NERC submitted a 

compliance filing to the Commission in 

Docket No. RR08–04–006 (Filing 2). In 

Filing 2, NERC submitted VSLs both for 

Reliability Standards that are pending at 

the Commission and Reliability 

Standards previously approved by the 

Commission. Filing 2 includes VSLs to 

supersede those in NERC’s Petition in 

Docket No. RM10–15–000 for EOP–001– 

1, IRO–002–2, IRO–004–2, IRO–005–3, 

IRO–008–1, IRO–009–1, IRO–010–1, 

IRO–010–1a, TOP–003–1, TOP–005–2, 

and TOP–006–2.42

NOPR Proposal 

71. In the NOPR, the Commission 

proposed to accept the proposed 

violation risk factors and violation 

severity levels presented in NERC’s 

petition. In addition, the Commission 

proposed to accept NERC’s commitment 

to review the proposed violation risk 

factors and violation severity levels to 

ensure compliance with the 

Commission’s guidelines. Accordingly, 

we proposed to direct NERC to submit 

a compliance filing within six months of 

the effective date of the final rule in this 

proceeding that would provide the 

results of NERC’s review including any 

modifications necessary to comply with 

the Commission’s guidelines on 

violation risk factors and violation 

severity levels. 

Commission Determination 

72. Because a determination has not 

yet been made regarding NERC’s ‘‘rollup’’ approach pending before the 

Commission in Docket Nos. RR08–4– 

005 and RR08–4–006, the Commission 

will defer discussion on the proposed 

violation risk factors and violation 

severity levels assigned to IRO–008–1, 

IRO–009–1, and IRO–010–1a, until after 

the Commission issues a final order 

acting on NERC’s petition in these 

proceedings. 

III. Information Collection Statement 

73. The information collection 

requirements in this Final Rule are 

identified under the Commission data 

collection FERC–725A, ‘‘Mandatory 

Reliability Standards for the Bulk-Power 

System.’’ The information collection 

requirements are being submitted to the 

Office of Management and Budget 

(OMB) for review under section 3507(d) 

of the Paperwork Reduction Act of 

1995.43 OMB’s regulations require OMB 

to approve certain information 

collection requirements imposed by 

agency rule.44

74. The Commission approves new 

Reliability Standards IRO–008–1, IRO– 

009–1, and IRO–010–1a; revised 

Reliability Standards EOP–001–1, IRO– 

002–2, IRO–004–2, IRO–005–3, TOP– 

003–1, TOP–005–2, and TOP–006–2; 

and the two new NERC Glossary terms: 

‘‘Operational Planning Analysis’’ and 

‘‘Real-time Assessment.’’ The three new 

Reliability Standards (IRO–008–1, IRO– 

009–1 and IRO–010–1a, governing 

reliability coordinator analyses, 

operational actions and data collection) 

replace parts of the currently-effective 

Reliability Standards EOP–001–0, IRO– 

002–1, IRO–004–1, IRO–005–2, TOP– 

003–0, TOP–005–1 and TOP–006–1 

approved by the Commission in Order 

No. 693. 

75. Thus, this final rule does not 

impose entirely new burdens on the 

affected entities. With the exception of 

the addition of Interchange Authority as 

an applicable entity in IRO–010–1a, the 

currently-effective standards EOP–001– 

0, IRO–002–1, IRO–004–1, IRO–005–2, 

TOP–003–0, TOP–005–1 and TOP–006– 

1 require actions by the same applicable 

group of entities. IRO–010–1a clarifies 

that balancing authorities, generator 

owners, generator operators, interchange 

authorities, load-serving entities, 

reliability coordinators, transmission 

operators, and transmission owners 

shall provide data and information, as 

specified, to the reliability 

coordinator(s) with which it has a 

reliability relationship.45 The 

requirements of IRO–008–1 and IRO– 

009–1 provide clarification from 

existing requirements, dictating the 

analysis and operational roles of the 

reliability coordinator. 

76. Public Reporting Burden: Our 

estimate below regarding the number of 

respondents is based on the NERC 

compliance registry as of September 28, 

2010. According to the NERC 

compliance registry, there are 134 

balancing authorities, 824 generator 

owners, 773 generator operators, 61 

interchange authorities, 541 loadserving entities, 26 reliability 

coordinators, 178 transmission 

operators, and 332 transmission owners 

that would be involved in providing 

information. However, under NERC’s 

compliance registration program, 

entities may be registered for multiple 

functions, and as such there is some 

duplication of functions regarding the 

number of registered entities that would 

be required to provide information. 

Given these parameters, the 

Commission estimates that the Public 

Reporting burden for the requirements 

contained in the final rule is as follows: 

FERC–725A data collection Number of 

respondents 

Number of 

annual 

responses 

Hours per 

respondent 

Total annual 

hours 

(A) (B) (C) (A × B × C) 

Reliability Coordinators distribution of data specification to entities 26 *1 8 208 

Balancing Authorities, Generator Owners, Generator Operators, 

Interchange Authorities, Load-serving Entities, Reliability Coordinators, Transmission Operators, and Transmission Owners 

reporting data to their Reliability Coordinator .............................. 1,501 *1 8 12,008 

Total .......................................................................................... ............................ ............................ ............................ 12,216 

*As needed. 


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16250 Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 

46Regulations 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). 

47 18 CFR 380.4(a)(5) (2010). 

48 5 U.S.C. 601–612. 

49The RFA definition of ‘‘small entity’’ refers to 

the definition provided in the Small Business Act 

(SBA), which defines a ‘‘small business concern’’ as 

a business that is independently owned and 

operated and that is not dominant in its field of 

operation. See 15 U.S.C. 632. According to the SBA, 

a small electric utility is defined as one that has a 

total electric output of less than four million MWh 

in the preceding year. 

• Total Information Collection Costs: 

The Commission estimated that it 

would require 12,216 total annual hours 

for the information collection (reporting 

and recordkeeping) and that the average 

annualized costs would be $1,465,920 

(12,216 hours @ $120/hour). 

Title: FERC–725A, Mandatory 

Reliability Standards for the Bulk-Power 

System. 

Action: Proposed Revision to FERC– 

725A. 

OMB Control No.: 1902–0244. 

Respondents: Businesses or other forprofit institutions; not-for-profit 

institutions. 

Frequency of Responses: On 

Occasion. 

Necessity of the Information: This 

Final Rule approves three Reliability 

Standards that pertain to 

interconnection reliability operating 

limits and seven modified Reliability 

Standards that pertain to emergency 

preparedness and operations, 

interconnection reliability operations 

and coordination, and transmission 

operations. This Final Rule also 

approves the addition of two new terms 

to the NERC Glossary of Terms. The 

Reliability Standards that pertain to 

interconnection reliability operating 

limits will require reliability 

coordinators and transmission operators 

to coordinate data on system operating 

limits and interconnection reliability 

operating limits. This Final Rule finds 

the Reliability Standards and related 

definitions just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

77. Interested persons may obtain 

information on the reporting 

requirements by contacting: Federal 

Energy Regulatory Commission, Attn: 

Ellen Brown, Office of the Executive 

Director, 888 First Street, NE. 

Washington, DC 20426, E-mail: 

DataClearance@ferc.gov, Tel: (202) 502– 

8663, Fax: (202) 273–0873. Comments 

on the requirements of this final rule 

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 email to OMB at 

oira_submission@omb.eop.gov. Please 

reference OMB Control Number 1902– 

0244, RIN 1902–AE17, and the docket 

number of this final rule in your 

submission. 

IV. Environmental Analysis 

78. 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.46 The Commission has 

categorically excluded certain actions 

from this requirement as not having a 

significant effect on the human 

environment. The actions directed here 

fall within the categorical exclusion in 

the Commission’s regulations for rules 

that are clarifying, corrective or 

procedural, for information gathering, 

analysis, and dissemination.47

Accordingly, neither an environmental 

impact statement nor environmental 

assessment is required. 

V. Regulatory Flexibility Act 

79. The Regulatory Flexibility Act of 

1980 (RFA) 48 generally requires a 

description and analysis of final rules 

that will have significant economic 

impact on a substantial number of small 

entities. The requirements of this rule 

would apply primarily to reliability 

coordinators, which do not fall within 

the definition of small entities.49

Moreover, the proposed Reliability 

Standards reflect a continuation of 

existing requirements for reliability 

coordinators and other entities to 

monitor, analyze, prevent, and mitigate 

the occurrence of operating limit 

violations on the Bulk-Power System. 

The one exception is the proposed new 

requirements in Reliability Standard 

IRO–010–1a for interchange authorities, 

which also do not fall within the 

definition of small entities. Based on the 

foregoing, the Commission certifies that 

this proposed rule will not have a 

significant impact on a substantial 

number of small entities. Accordingly, 

no regulatory flexibility analysis is 

required. 

VI. Document Availability 

80. 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. 

81. 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. 

82. 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 

83. These regulations are effective 

May 23, 2011. 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. 

List of Subjects in 18 CFR Part 40 

Electric power, Electric utilities, 

Reporting and recordkeeping 

requirements. 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

[FR Doc. 2011–6778 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. RM10–10–000; Order No. 747] 

Planning Resource Adequacy 

Assessment Reliability Standard 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Final rule. 

SUMMARY: Under section 215(d)(2) of the 

Federal Power Act, the Federal Energy 

Regulatory Commission approves 

regional Reliability Standard, BAL–502– 

RFC–02 (Planning Resource Adequacy 

Analysis, Assessment and 


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