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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Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 16251 

1See 16 U.S.C. 824o(e)(3) (2006). 

2North American Electric Reliability Corp., 116 

FERC ¶ 61,062 (ERO Certification Order), order on 

reh’g & compliance, 117 FERC ¶ 61,126 (2006), aff’d 

sub nom. Alcoa, Inc. v. FERC, 564 F.3d 1342 (D.C. 

Cir. 2009). 

3 16 U.S.C. 824o(e)(4). 

4Rules Concerning Certification of the Electric 

Reliability Organization; Procedures for the 

Establishment, Approval, and Enforcement of 

Electric Reliability Standards, Order No. 672, FERC 

Stats. & Regs. ¶ 31,204, at P 290; order on reh’g, 

Order No. 672–A, FERC Stats. & Regs. ¶ 31,212 

(2006). 

5 Id. P 291. 

6See North American Electric Reliability Corp., 

119 FERC ¶ 61,060, at P 316–350 (Delegation 

Agreement Order), order on reh’g, 120 FERC 

¶ 61,260 (2007). 

7 Id. P 339. 

8 16 U.S.C. 824o. 

9NERC Petition for Approval of Proposed RFC 

Regional Reliability Standard BAL–502–RFC–02, 

Docket No. RM10–10–000 (Dec. 14, 2009) (Petition). 

10 Id. at 7. NERC notes that it has a pending 

continent-wide project, Project 2009–05, Resource 

Adequacy Assessments, which is intended to 

address resource adequacy assessments. 

11NERC Petition at 7. 

12Currently, there are four registered planning 

coordinators in the RFC region: American 

Transmission Co., LLC; International Transmission 

Company (ITC Transmission); Midwest 

Independent Transmission System Operator, Inc. 

(Midwest ISO); and PJM Interconnection, LLC 

(PJM). 

Documentation), developed by 

ReliabilityFirst Corporation (RFC) and 

submitted to the Commission by the 

North American Electric Reliability 

Corporation. The approved regional 

Reliability Standard requires planning 

coordinators within the RFC 

geographical footprint to analyze, assess 

and document resource adequacy for 

load in the RFC footprint annually, to 

utilize a ‘‘one day in ten years’’ loss of 

load criterion, and to document and 

post load and resource capability in 

each area or transmission-constrained 

sub-area identified. The Commission 

also approves four regional reliability 

definitions related to the approved 

regional Reliability Standard and the 

violation risk factors and violation 

severity levels assigned to the BAL– 

502–RFC–02 Requirements. 

DATES: Effective Date: This Rule will 

become effective May 23, 2011. 

FOR FURTHER INFORMATION CONTACT: 

Karin L. Larson (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426, (202) 502–8236. 

Scott Sells (Technical Information), 

Office of Electric Reliability, Division 

of Policy Analysis and Rulemaking, 

Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502– 

6664. 

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(d)(2) of the 

Federal Power Act (FPA), the 

Commission approves regional 

Reliability Standard BAL–502–RFC–02 

(Planning Resource Adequacy Analysis, 

Assessment and Documentation), 

developed by ReliabilityFirst 

Corporation (RFC) and submitted to the 

Commission by the North American 

Electric Reliability Corporation (NERC). 

The approved regional Reliability 

Standard requires planning coordinators 

within the RFC geographical footprint to 

analyze, assess and document resource 

adequacy for load in the RFC footprint 

annually, to utilize a ‘‘one day in ten 

years’’ loss of load criterion, and to 

document and post load and resource 

capability in each area or transmissionconstrained sub-area identified. The 

Commission also approves four regional 

reliability definitions related to the 

approved regional Reliability Standard 

and the violation risk factors and 

violation severity levels assigned to the 

BAL–502–RFC–02 Requirements. 

I. Background 

2. Section 215 of the FPA requires a 

Commission-certified Electric 

Reliability Organization (ERO) to 

develop mandatory and enforceable 

Reliability Standards, which are subject 

to Commission review and approval. 

Once approved, the Reliability 

Standards may be enforced by the ERO, 

subject to Commission oversight, or by 

the Commission independently.1 In July 

2006, the Commission certified NERC as 

the ERO.2 Reliability Standards that the 

ERO proposes to the Commission may 

include Reliability Standards that are 

developed by a Regional Entity.3 In 

Order No. 672, the Commission urged 

uniformity of Reliability Standards, but 

recognized a potential need for regional 

differences.4 Accordingly, the 

Commission stated that: 

As a general matter, we will accept the 

following two types of regional differences, 

provided they are otherwise just, reasonable, 

not unduly discriminatory or preferential and 

in the public interest, as required under the 

statute: (1) A regional difference that is more 

stringent than the continent-wide Reliability 

Standard, including a regional difference that 

addresses matters that the continent-wide 

Reliability Standard does not; and (2) a 

regional Reliability Standard that is 

necessitated by a physical difference in the 

Bulk-Power System.[5] 

A. ReliabilityFirst 

3. On April 19, 2007, the Commission 

approved delegation agreements 

between NERC and eight Regional 

Entities.6 In the Delegation Agreement 

Order, the Commission accepted RFC as 

a Regional Entity and accepted RFC’s 

Standards Development Manual, which 

sets forth the process for RFC’s 

development of regional Reliability 

Standards.7 The RFC region is a less 

than interconnection-wide region that 

covers all or portions of 14 states and 

the District of Columbia. 

B. Regional Reliability Standard BAL– 

502–RFC–02 

4. On December 14, 2009, NERC 

submitted for Commission approval, in 

accordance with section 215(d)(1) of the 

FPA,8 regional Reliability Standard 

BAL–502–RFC–02 and four associated 

new definitions.9 NERC stated that the 

proposed regional Reliability Standard 

establishes requirements for planning 

coordinators in the RFC region 

regarding resource adequacy 

assessment, which subject matter is not 

currently addressed in NERC’s 

continent-wide Reliability Standards.10

The stated purpose of this regional 

Reliability Standard is to establish 

common criteria, based on ‘‘one day in 

ten years’’ loss of load expectation 

principles, for the analysis, assessment 

and documentation of resource 

adequacy for load in the RFC region.11

5. Regional Reliability Standard BAL– 

502–RFC–02 contains the following two 

main requirements. Requirement R1 

requires each planning coordinator in 

RFC’s footprint 12 to perform and 

document an annual resource adequacy 

analysis. The sub-requirements of 

Requirement R1 set forth the criteria to 

be used for the resource adequacy 

analysis. Requirement R2 requires each 

planning coordinator to annually 

document the projected load and 

resource capability for each area and 

transmission constrained sub-area 

identified in the analysis. The subrequirements of Requirement R2 set 

forth the specific documentation 

requirements. Each of the two main 

requirements is assigned a violation risk 

factor (VRF) and violation severity level 

(VSL). RFC did not assign VRFs or VSLs 

to the sub-requirements. 

6. The NERC Petition also includes 

the following four new regional 

definitions related to regional Reliability 

Standard BAL–502–RFC–02. First, 

‘‘Resource Adequacy,’’ which is defined 

as the ability of supply-side and 

demand-side resources to meet the 


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16252 Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 

13Planning Resource Adequacy Assessment 

Reliability Standard, 75 FR 66038 (October 27, 

2010), FERC Stats. & Regs. ¶ 32,662 (2010) 

(‘‘NOPR’’). 

14NERC’s Glossary lists each term that has been 

defined for use in one or more of NERC’s continentwide or regional Reliability Standards. 

aggregate electrical demand (including 

losses). Second, ‘‘Net Internal Demand,’’ 

which is defined as the total of all enduse customer demand and electric 

system losses within specified metered 

boundaries, less Direct Control Load 

Management and Interruptible Demand. 

Third, ‘‘Peak Period,’’ which is defined 

as a period consisting of two (2) or more 

calendar months but less than seven (7) 

calendar months, which includes the 

period during which the responsible 

entity’s annual peak demand is 

expected to occur. Fourth, ‘‘Year One,’’ 

the planning year that begins with the 

upcoming annual Peak Period. These 

four defined terms would apply in the 

RFC region only. 

C. Notice of Proposed Rulemaking 

7. On October 21, 2010, the 

Commission issued its Notice of 

Proposed Rulemaking (NOPR) 

proposing to approve regional 

Reliability Standard BAL–502–RFC–02, 

stating that the standard will improve 

the reliable operation of the Bulk-Power 

System by ensuring use in the RFC 

region of a common criterion, the ‘‘one 

day in ten years’’ principle, to assess 

resource adequacy during the planning 

horizon.13 In the NOPR, the 

Commission proposed to direct RFC, at 

the time it conducts its scheduled fiveyear review of regional Reliability 

Standard BAL–502–RFC–02, to: (1) Add 

time horizons to the two main 

requirements, and (2) consider 

modifying the regional Reliability 

Standard to include a requirement that 

the planning coordinators identify any 

gap between the needed amount of 

planning reserves defined in 

Requirement R1.1 and the planning 

reserves determined from the resource 

adequacy analysis. The Commission 

also proposed to accept the four related 

definitions for inclusion in NERC’s 

Glossary for use with RFC’s regional 

Reliability Standards,14 and proposed to 

defer ruling on the proposed VRFs and 

VSLs for the standard. 

8. In addition, in the NOPR, the 

Commission sought clarification or 

comment on a few aspects of BAL–502– 

RFC–02. With respect to the regional 

Reliability Standard’s resource 

adequacy analysis, the Commission 

sought comment on three issues: (1) The 

loss of load calculation; (2) 

consideration of the capacity benefit 

margin; and (3) evaluation of common 

mode outages. The Commission also 

sought comment on: (1) How planning 

coordinators, when conducting the 

resource adequacy analysis, will address 

load and resources outside of the RFC 

footprint; (2) whether planning 

coordinators should have a common 

process or procedure that addresses the 

planning reserves assessments; and (3) 

whether the planning coordinators have 

experienced problems collecting the 

data necessary to perform the resource 

adequacy analysis. 

9. In response to the NOPR, comments 

were filed by 13 interested parties. 

These comments assisted us in the 

evaluation of BAL–502–RFC–02. In the 

discussion below, we address the issues 

raised by these comments. In addition, 

five entities filed motions to intervene 

and three state utility commissions filed 

notices of intervention. Appendix A to 

this Final Rule lists the entities that 

filed comments and interventions. 

II. Discussion 

10. In this Final Rule, the Commission 

approves regional Reliability Standard 

BAL–502–RFC–02 as just, reasonable, 

not unduly discriminatory or 

preferential, and in the public interest. 

To that end, the Commission finds that 

BAL–502–RFC–02 satisfies the Order 

No. 672 factors on how the Commission 

determines whether a regional 

Reliability Standard is just and 

reasonable in that BAL–502–RFC–02: (1) 

Is clear and unambiguous regarding 

what is required and who is required to 

comply (planning coordinator); (2) has 

clear and objective measures for 

compliance and achieves a reliability 

goal (namely, providing a common 

framework for resource adequacy 

analysis, assessment, and 

documentation) using one effective 

methodology, and (3) is ‘‘more stringent’’ 

in that NERC’s continent-wide 

standards currently do not address 

assessment of resource adequacy in the 

planning horizon. 

11. The Commission also denies the 

requests made by NARUC, Ohio PUC, 

Borlick, and the Illinois Commerce 

Commission that the Commission hold 

a technical conference in this 

proceeding to ‘‘foster needed dialogue’’ 

by state regulatory commissions, 

economists, and stakeholders regarding 

the one in ten years criterion. First, the 

Commission finds that there is adequate 

information in the record in this 

proceeding to act on NERC’s Petition. 

Second, the more appropriate venue to 

discuss technical details, such as the 

appropriateness of the one day in ten 

years criterion compared with other 

methodologies, is in the standards 

development process itself. The 

Commission’s decision here does not 

preclude other entities, such as NERC, 

from holding technical conferences to 

foster further dialogue and to discuss 

improvements in criteria used for 

resource planning. 

12. The following discussion 

addresses first, the two challenges to 

approval of BAL–502–RFC–02, the 

Commission’s jurisdictional authority to 

approve a resource adequacy assessment 

standard and the propriety of using the 

one day in ten years criterion. As 

discussed below, on these two issues 

the Commission determines first, that it 

is within our authority to approve a 

resource adequacy assessment regional 

Reliability Standard and, second, that 

the one day in ten years criterion is a 

just and reasonable method to use to 

conduct resource adequacy assessments 

for purposes of BAL–502–RFC–02. Next, 

the Commission discusses the six issues 

on which we sought comment in the 

NOPR. Finally, the Commission 

discusses the following remaining 

issues related to BAL–502–RFC–02: (i) 

Missing time horizons, (ii) effective 

date, (iii) regional definitions, and (iv) 

VRFs and VSLs. 

A. Challenges To Approving BAL–502– 

RFC–02 

13. NERC, RFC and other commenters 

support approval of regional Reliability 

Standard BAL–502–RFC–02. NARUC 

and Ohio PUC raise concerns regarding 

the Commission’s jurisdiction to 

approve this regional Reliability 

Standard. Commenters also raise 

concerns regarding the appropriateness 

of the one day in ten years criterion. 

These issues are discussed below. 

1. Jurisdiction 

Comments 

14. NARUC and the Ohio PUC raise 

several jurisdictional arguments 

regarding the Commission’s authority 

under section 215 of the FPA to approve 

regional Reliability Standard BAL–502– 

RFC–02. These comments are endorsed 

by the Illinois Commerce Commission. 

NARUC and the Ohio PUC argue that 

the Commission lacks jurisdiction under 

section 215 of the FPA to approve a 

regional Reliability Standard that 

pertains to resource adequacy, asserting 

that BAL–502–RFC–02 is, in reality, a 

capacity requirement that RFC has 

couched as a planning tool. The Ohio 

PUC quotes Order No. 672, in which the 

Commission stated: ‘‘The proposed 

Reliability Standard must address a 

reliability concern that falls within the 

requirements of section 215 of the FPA. 

That is, it must provide for the reliable 

operation of Bulk-Power System 


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15Ohio PUC Comments at 7, Order No. 672, FERC 

Stats. & Regs. ¶ 31,204 at P 331. 

16 ‘‘Reliability Standard’’ is defined to mean ‘‘a 

requirement, approved by the Commission under 

this section, to provide for reliable operation of the 

bulk-power system. The term includes requirements 

for the operation of existing bulk-power system 

facilities, including cybersecurity protection, and 

the design of planned additions or modifications to 

such facilities to the extent necessary to provide for 

reliable operation of the bulk-power system, but the 

term does not include any requirement to enlarge 

such facilities or to construct new transmission 

capacity or generation capacity.’’ 16 U.S.C. 

824o(a)(3). 

17The term ‘‘Reliable Operation,’’ as defined in 

section 215(a)(4) of the FPA, means ‘‘operating the 

elements of the bulk-power system within 

equipment and electric system thermal, voltage, and 

stability limits so that instability, uncontrolled 

separation, or cascading failures of such system will 

not occur as a result of a sudden disturbance, 

including a cybersecurity incident, or unanticipated 

failure of system elements.’’ 

18Order No. 672, FERC Stats. & Regs. ¶ 31,204 at 

P 806 (emphasis added). 

19NERC Reply Comments at 5. 

20RFC Reply Comments at 11. 

facilities. It may not extend beyond 

reliable operation of such facilities or 

apply to other facilities.’’ 15 The Ohio 

PUC and NARUC argue that BAL–502– 

RFC–02 fails this parameter as it does 

not provide for the reliable operation of 

Bulk-Power System facilities. 

Specifically, they point to the 

definitions of ‘‘Reliability Standard’’ and 

‘‘Reliable Operation’’ set forth in section 

215 of the FPA, which definitions they 

argue make clear that Congress did not 

intend for a resource adequacy planning 

criterion to be the subject of a FPA 

section 215 Reliability Standard. They 

claim that the statutory definition of 

‘‘Reliability Standard,’’ specifically 

precludes the Commission from 

instituting any capacity requirements.16

They next posit that the definition of 

‘‘Reliable Operation’’ pertains to 

cascading outages, not the orderly 

shedding of load due to a capacity 

shortage.17 The Ohio PUC argues that a 

lack of adequate resources to serve all 

‘‘firm’’ load at current prices does not 

lead to ‘‘instability, uncontrolled 

separation, or cascading failures’’ in the 

Bulk-Power System. Thus, NARUC and 

Ohio PUC argue that BAL–502–RFC–02, 

which requires a resource adequacy 

assessment, does not address a 

reliability concern as resource adequacy 

issues are not relevant to the ‘‘Reliable 

Operation’’ of Bulk-Power System 

facilities as that term is defined in 

section 215 of the FPA. 

15. NARUC and Ohio PUC also 

contend that resource adequacy is a 

traditional state concern that is outside 

of the Commission’s domain. They 

argue that both capacity requirements 

and resource adequacy planning criteria 

involve economic and policy decisions 

that impact the reasonableness of rates, 

generation decisions and retail demand 

response programs, all of which are 

within the states’ domain. The Ohio 

PUC states that a Commission-mandated 

resource adequacy Reliability Standard, 

such as BAL–502–RFC–02, infringes on 

a state’s authority to balance need for 

capacity investments against the risk of 

curtailments. Following up on this 

point, the Ohio PUC states in a footnote 

that it is unreasonable for anyone to 

argue that planning coordinators would 

plan using one criterion and then use a 

different criterion to make the economic 

determination of what resources should 

be acquired as doing so would be a 

waste of the planning coordinator’s time 

and resources. 

16. NERC, RFC, and the PJM Power 

Providers respond to the jurisdictional 

questions raised by NARUC and Ohio 

PUC in their reply comments. In its 

Petition, NERC asserted that regional 

Reliability Standard BAL–502–RFC–02 

does not adversely affect competition or 

cause restriction on the grid because it 

does not require entities to secure the 

needed resources as an outcome of the 

planning coordinators resource 

adequacy analysis. In their reply 

comments, NERC, RFC, and PJM Power 

Providers reiterate that BAL–502–RFC– 

02 is consistent with the provisions and 

stated goals of the Energy Policy Act of 

2005. 

17. NERC counters NARUC’s and the 

Ohio PUC’s comments, arguing that 

section 215(a)(3), which contains the 

definition of ‘‘Reliability Standard,’’ 

does not preclude NERC from including 

a resource adequacy planning criterion. 

NERC states that the key distinction is 

between NERC’s ability to include 

resource adequacy planning criterion in 

a Reliability Standard, which is clearly 

allowed under section 215(a)(3) and 

prior Commission orders, and NERC’s 

ability to require the building or 

acquisition of new generating capacity, 

which is prohibited by section 215(a)(3) 

of the FPA. To support this argument, 

NERC quotes Order No. 672 in which 

the Commission stated: 

We agree with PG&E’s recommendation 

that the Commission require the ERO to 

obtain information on resource adequacy and 

make related recommendations where 

entities are found to have inadequate 

resources. Resource adequacy is a 

fundamental aspect of reliability. The ERO is 

in a unique position to obtain and analyze 

information regarding resource adequacy 

across all regions of the Bulk-Power System 

in interconnected North America. Although 

section 215(a)(3) of the FPA provides that the 

term Reliability Standard does not include 

any requirement to enlarge Bulk-Power 

System facilities or to construct new 

transmission capacity or generation capacity, 

it does not preclude the ERO from obtaining 

information relating to resource adequacy for 

the purposes of making its required reports 

on the adequacy of the Bulk-Power System 

pursuant to section 215(g) of the FPA.18

NERC asserts that the common 

criterion established in regional 

Reliability Standard BAL–502–RFC–02 

to be used to complete a resource 

adequacy assessment serves a reliability 

purpose as the ‘‘common criterion is 

necessary so that recommendations can 

be made in the [RFC] Region regarding 

inadequate resource adequacy 

requirements that could negatively 

impact the reliability of the bulk power 

system.’’ 19

18. RFC argues that Reliability 

Standards are not simply engineering 

standards and that many Reliability 

Standards, like BAL–502–RFC–02, 

involve long horizons and are intended 

to prevent the Bulk-Power System from 

coming anywhere near ‘‘instability, 

uncontrolled separation, or cascading 

failures.’’ As an example, RFC cites to 

NERC Reliability Standard FAC–010, 

which requires planning authorities to 

identify system operating limits (SOLs) 

and interconnection reliability operating 

limits (IROLs) in the planning horizon. 

RFC also cites to NERC Reliability 

Standard TPL–001, which requires that 

the transmission system be able to 

supply projected customer demands 

over the range of forecast system 

demands under no contingency 

conditions for the planning horizon. 

With respect to proposed regional 

Reliability Standard BAL–502–RFC–02, 

RFC states that the resource adequacy 

data produced under the standard will 

be a ‘‘valuable reliability tool that can be 

used by registered entities in working to 

ensure, well in advance of any 

identified concerns, that ‘instability, 

uncontrolled separation, or cascading 

failures’ never occur.’’ 20

19. With respect to NARUC and the 

Ohio PUC’s arguments that a resource 

adequacy assessment standard will 

infringe on areas within a state’s 

jurisdiction, RFC responds that BAL– 

502–RFC–02 does not encroach on the 

authority of the states to make the 

policy decisions that weigh resource 

adequacy against cost. RFC notes that 

states within the RFC region are free to 

use the data and documentation 

developed under BAL–502–RFC–02 in 

imposing resource adequacy obligations 

and making policy decisions regarding 

what level of service they are willing to 

pay to achieve. RFC further asserts that 

each state commission remains the 

ultimate arbiter of economic decisions 

regarding how to balance capacity 


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21Cal. Indep. Sys. Operator Corp., 116 FERC ¶ 

61,274, at P 1112 (2006) (stating that resource 

adequacy affects the ability of the operator of the 

interstate transmission grid to ensure reliable 

service). 22FPA section 215(g) provides that the ‘‘ERO shall 

conduct periodic assessments of the reliability and 

adequacy of the bulk-power system in North 

America.’’ 16 U.S.C. 824o(g) (emphasis added). 

23North American Electric Reliability 

Corporation, 116 FERC ¶ 61,062, at P 292 (2006) 

(citing Order No. 672, FERC Stats. & Regs. ¶ 31,204 

at P 805–806). 

24New York State Reliability Council, 122 FERC 

¶ 61,153, at P 33 (2008) (emphasis added). 

25 16 U.S.C. 824o(a)(3). 

26Ohio PUC Comments at 5–6. 

investments against the risk of 

curtailment as no economic decisions of 

any kind are mandated by BAL–502– 

RFC–02. RFC reiterates that the only 

enforceable mandate under BAL–502– 

RFC–02 is the obligation to perform and 

document the resource adequacy 

analysis in a consistent way across the 

RFC region. 

Commission Determination 

20. As explained herein, the 

Reliability Standard before us does not 

preclude or preempt any action by a 

state PUC with regard to resource 

adequacy. As the Commission has 

previously recognized, resource 

adequacy raises ‘‘complex jurisdictional 

concerns’’ which at times are at the 

‘‘confluence of state-federal 

jurisdiction.’’ 21 As the Commission 

stated in the order in which the 

Commission certified NERC as the ERO, 

with respect to FPA section 215(g), 

‘‘Reliability Reports’’: 22

We agree * * * that the ERO’s assessments 

of Bulk-Power System reliability and 

adequacy cannot themselves provide the 

basis for preempting state or regional 

transmission planning and resource 

adequacy programs. The Commission can, 

however, order the ERO to submit adequacy 

assessments, including recommendations 

that some entities are found to have 

inadequate resources. In addition, our 

regulations provide for a determination of 

consistency between state actions and a 

Reliability Standard, as well as an assessment 

of the Reliability Standard’s effectiveness as 

the Commission may deem appropriate.23

Although the Commission was 

addressing the interplay between the 

ERO’s role with respect to resource 

adequacy assessments and states’ 

resource adequacy programs in the 

context of section 215(g), this interplay 

is equally relevant to the ERO’s role 

with respect to the development of 

Reliability Standards because the 

Commission is acknowledging that FPA 

section 215 establishes resource 

adequacy assessments as being relevant 

to reliability and, further, that the 

reliability aspect of resource adequacy 

assessments does not preempt state 

action. 

21. The Commission, by approving 

BAL–502–RFC–02, is not usurping, 

intruding on, or preempting any 

authority exclusively within a state’s 

jurisdiction because, as recognized in 

Order No. 672, the FPA does not reserve 

authority for the states over all matters 

related to or that flow from ‘‘resource 

adequacy.’’ Moreover, the ‘‘savings’’ 

provision in section 215, section 

215(i)(3), is clear that nothing in section 

215 shall be ‘‘construed to preempt any 

authority of any State to take action to 

ensure the safety, adequacy, and 

reliability of electric service within that 

State, as long as such [State] action is 

not inconsistent with any reliability 

standard.’’ As we have clarified in a 

prior order, the saving provision in 

section 215(i) is not a grant of new 

authority to the states, but merely 

preserves any authority states may have 

under state law ‘‘to take action to ensure 

the safety, adequacy, and reliability of 

electric service within that State, so long 

as such action is not inconsistent with 

any reliability standard * * * .’’ 24 Thus, 

we do not agree with NARUC or the 

Ohio PUC that the approval of BAL– 

502–RFC–02 will impinge on states’ 

jurisdiction over matters related to 

resource adequacy. BAL–502–RFC–02 

does not touch the establishment of 

specific resource adequacy 

requirements, and thus does not intrude 

on the state’s decisional authority with 

respect to building or acquisition of 

assets or capacity to meet resource 

adequacy needs. 

22. With respect to the Ohio PUC’s 

argument that by approving a regional 

Reliability Standard mandating the use 

of a specific resource adequacy planning 

criterion (the one day in ten years 

criterion), the Commission is 

establishing that criterion as the de facto 

criterion to be used to set resource 

investment requirements, this argument 

appears to be borne out of the Ohio 

PUC’s concern regarding preserving its 

authority to set resource adequacy 

standards. The standard does not 

impinge on Ohio PUC’s authority to set 

or determine how to meet resource 

adequacy standards. Contrary to the 

Ohio PUC’s concerns, the Commission 

believes that establishing a common 

criterion for resource planning will 

provide states with a uniform 

framework of information regarding 

resource adequacy. The information the 

reliability assessments provide would 

then be available to the states to use or 

could serve as a platform on which to 

layer additional factors, such as costs, as 

the states see fit. 

23. The Commission also finds that 

the proposed resource adequacy 

analyses and documentation 

requirements in BAL–502–RFC–02 fall 

within the definition of ‘‘Reliability 

Standard’’ as that term is defined in 

section 215(a)(3) and pertain to the 

‘‘Reliable Operation’’ of the Bulk-Power 

System as that term is defined in section 

215(a)(4). Under section 215(a)(3), the 

only type of requirement that is 

explicitly precluded from being part of 

an enforceable Reliability Standard is a 

‘‘requirement to enlarge [bulk-power 

system facilities] or to construct new 

transmission capacity or generation 

capacity.’’ 25 BAL–502–RFC–02 does not 

include any such requirement. 

Specifically, BAL–502–RFC–02 

mandates planning, it does not require 

entities to secure any resources as an 

outcome of the resource adequacy 

assessment. 

24. BAL–502–RFC–02 also falls 

within the definition of Reliability 

Standard, as it provides for the reliable 

operation of the Bulk-Power System 

because it serves to identify potential 

resource adequacy deficiencies in a 

planning horizon with time to mitigate 

projected resource adequacy problems 

before shortages of resources occur in 

the operating horizon. Shortages of 

resources in the operating horizon can 

lead to blackouts and even cascading 

outages. Under these conditions, 

operators may be continually challenged 

to balance load with energy to prevent 

major power or voltage swings across 

the grid that can lead to blackouts and 

cascading outages. Because the standard 

does not prescribe that action must be 

taken, entities with authority for 

planning and siting new resources, 

including demand response resources or 

any other resource type, can determine 

the appropriate course of action, if any, 

that should be taken, including 

performing additional resource 

adequacy studies. The standard 

therefore does not preclude or preempt 

any action by a state commission with 

regard to resource adequacy. The Ohio 

PUC argues that NERC and RFC 

‘‘conflate[] resource adequacy with 

reliable operation of the Bulk-Power 

System,’’ stating that the definition of 

‘‘Reliable Operation’’ cannot be enlarged 

and manipulated to include planning to 

build such capacity.26 The Commission 

finds that the Ohio PUC, in making this 

argument, is reading into BAL–502– 

RFC–02 a requirement that registered 

entities within RFC build or acquire 

new generating capacity. Such a 

requirement simply does not exist in 

BAL–502–RFC–02. 


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27 16 U.S.C. 824o(i)(2). 

28The ‘‘one day in ten years’’ criterion is used to 

plan resource adequacy such that reserve margins 

are planned so that the expected frequency of loss 

of load due to inadequate resources does not exceed 

0.1 events per year, which equates to one event in 

ten years. 

29See proposed Reliability Standard BAL–502– 

RFC–02, Requirement R1.2. 

30See Comments submitted by Borlick, Carden, 

OCC, Ohio PUC, and Wilson. 31RFC Reply Comment at 13. 

25. Ohio PUC further argues that a 

lack of adequate resources to serve firm 

load does not lead to ‘‘instability, 

uncontrolled separation or cascading 

failures,’’ which are hallmarks of the 

term ‘‘Reliable Operation.’’ We disagree 

with the Ohio PUC’s interpretation of 

the definition of ‘‘Reliable Operation’’ as 

stated in section 215. A more careful 

reading reveals that the ‘‘hallmarks’’ of 

this term, instability, uncontrolled 

separation or cascading failures, are not 

to occur upon the unanticipated failure 

of a system element. If resources cannot 

meet load, or are insufficient to provide 

a reserve margin above expected load, 

then instability, uncontrolled separation 

or cascading failures can result from the 

unanticipated loss of a system element. 

If this situation occurs, reliable 

operation is not achieved due to 

resource inadequacy. Thus, like other 

planning standards, BAL–502–RFC–02 

provides for the reliable operation of the 

Bulk-Power System as it will help 

identify areas of concern that, if left 

unresolved, could result in future 

instability, uncontrolled separation, or 

cascading failures of the Bulk-Power 

System. 

26. The only other affirmative 

limitation on the scope of Commissionapproved and enforceable Reliability 

Standards under FPA section 215 is the 

savings clause in section 215(i)(2), 

which states: ‘‘This section does not 

authorize the ERO or the Commission to 

order the construction of additional 

generation or transmission capacity or 

to set and enforce compliance with 

standards for adequacy or safety of 

electric facilities or services.’’ 27

Regional Reliability Standard BAL–502– 

RFC–02 does not set any resource 

adequacy standards. Specifically, BAL– 

502–RFC–02 does not impose on any 

registered entity a resource adequacy 

obligation because the standard contains 

no requirement for an entity to construct 

or otherwise invest in additional 

transmission, distribution, or generation 

resources or capacity. Nothing in BAL– 

502–RFC–02 requires any entity to use 

or take any action with respect to the 

resulting resource adequacy assessment. 

Regional Reliability Standard BAL–502– 

RFC–02 only requires a resource 

adequacy analysis and documentation 

of such analysis. Importantly, the 

Commission is not, through BAL–502– 

RFC–02, setting, enforcing or in any way 

mandating the resource adequacy levels 

that are derived through the BAL–502– 

RFC–02 resource adequacy analyses. 

Accordingly, BAL–502–RFC–02 does 

not run afoul of the prohibitions in FPA 

sections 215(a)(3) or 215(i)(2). 

2. One Day in Ten Years Criterion 

27. Regional Reliability Standard 

BAL–502–RFC–02 requires planning 

coordinators to perform an annual 

resource adequacy analysis and 

calculate a planning reserve margin that 

meets the ‘‘one day in ten years’’ 

criterion.28 The analysis must be 

‘‘performed or verified separately’’ for: 

(i) Year one, (ii) for one year falling in 

the second through fifth years, and (iii) 

at least one year in the sixth through 

tenth years.29

Comments 

28. Several commenters expressed 

that the ‘‘one day in ten years’’ criterion 

is not economically efficient, is 

outdated, and is too conservative of a 

requirement.30 OCC comments that the 

‘‘one day in ten years’’ criterion does not 

account for changes in the electric 

industry such as markets, demand 

response, energy advancements, 

distributed generation, energy efficiency 

or the smart grid. Thus, OCC 

recommends that the Commission 

consider alternative planning reserve 

margin methodologies rather than a 

conservative one day in ten years 

methodology. The Ohio PUC argues that 

the one day in ten years criterion has 

not been shown to be just and 

reasonable because: (1) The criterion is 

outdated; (2) it may negatively impact 

competition such as the development of 

price responsive demand; and (3) no 

analysis has been done to confirm that 

a one day in ten years criterion 

produces a reserve margin that 

reasonably balances the value of 

avoiding scarcity and the cost of 

maintaining the target reserve margin. 

29. Carden supports annual resource 

adequacy assessments that are based on 

common criteria for reliability. Wilson 

comments that the conservative 

assumptions in a one day in ten years 

analysis often lead to less reliance on 

neighboring systems that results in 

excess generation. 

30. Responding to these criticisms of 

the one day in ten years criterion, RFC 

points out that the only RFC stakeholder 

that voted against the BAL–502–RFC–02 

cast a negative vote because that 

stakeholder favors implementing a 

continent-wide resource adequacy 

planning standard rather than a regional 

standard. RFC asserts that the one day 

in ten years criterion is just and 

reasonable because its use will ensure, 

for the first time, that similar 

assessments of resource adequacy are 

performed for every part of the RFC 

region, including in states that have 

deregulated electric markets, which will 

provide a consistent and mutually 

understandable target against which to 

assess adequacy. RFC rejects as 

unreasonable, burdensome and 

unnecessary the other commenters’ 

suggestion that the one day in ten years 

criterion must be first proven to balance 

the benefit of avoiding scarcity with the 

cost of maintaining an appropriate 

reserve. RFC further notes that even 

though the criterion used in regional 

Reliability Standard BAL–502–RFC–02 

could be improved in the future, that 

does not make the standard 

unreasonable now. To that end, RFC 

encourages interested parties to 

participate regularly in its regional 

Reliability Standards development 

process as well as at its informal 

stakeholder meetings. 

Commission Determination 

31. The comments on this issue reveal 

a level of disagreement regarding the 

appropriateness of using the ‘‘one day in 

ten years’’ criterion for an annual 

resource adequacy assessment. In 

approving this regional Reliability 

Standard, the Commission need not 

determine that the ‘‘one day in ten 

years’’ criterion represents the most 

effective or most economically efficient 

method of measuring resource 

adequacy. Rather, the Commission is to 

determine whether the proposed 

standard is just and reasonable, not 

unduly discriminatory or preferential, 

and in the public interest. Thus, in this 

case, the Commission considers whether 

the requirements in BAL–502–RFC–02 

are a just and reasonable means of 

achieving the reliability objective of the 

standard. As noted by RFC in its reply 

comments, the reliability objective of 

BAL–502–RFC–02 is to provide a 

common framework for analyzing, 

assessing, and documenting resource 

adequacy, in part to resolve RFC’s 

concerns regarding the lack of 

standardization and the lack of a 

measure for resource adequacy in 

deregulated states within its footprint.31

The Commission finds that BAL–502– 

RFC–02 achieves the reliability 

objective of establishing a common 

criteria for analyzing, assessing and 

documenting resource adequacy in a 


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32See, e.g., Midwest Independent Transmission 

System Operator, Inc., 122 FERC ¶ 61,283, at P 108 

(2008) (accepting the Midwest ISO’s proposal to use 

the one day in ten years standard as reasonable and 

consistent with industry standard); Devon Power 

LLC, et al., 110 FERC ¶ 61,313, at P 8 (2005) (noting 

that the ISO–NE uses as a regional planning criteria 

the one day in ten years criterion); see also North 

American Electric Reliability Council, Resource and 

Transmission Adequacy Task Force, Resource and 

Transmission Adequacy Recommendations, June 

15, 2004, available at http://www.nerc.com/docs/

docs/pubs/Resource_and_Transmission_Adequacy_

Recommendations.pdf (survey of the criteria used 

for resource adequacy planning during 2003–2004 

timeframe showed that of the eight regional 

reliability councils polled in the East, five use the 

one day in ten years LOLE criteria); PJM 

Interconnection, L.L.C., PJM Generation Adequacy 

Analysis: Technical Methods Capacity Adequacy 

Planning Department, at 1 (October 2003), available 

at http://www.nerc.com/docs/pc/ris/PJM_

Generation_Adequacy_Analysis_Technical_

Methods.pdf (stating ‘‘This ‘one day in ten year’ 

loss-of-load expectation (LOLE) is the standard 

observed in most NERC regions and is the basis for 

determining PJM’s required Installed Reserve 

Margin (IRM).’’). 

33NERC Petition at 10. 

34See e.g., Version One Regional Reliability 

Standard Resource and Demand Balancing, 133 

FERC ¶ 61,063, at P 30 (2010) (Order No. 740) 

(remanding regional Reliability Standard BAL–002– 

WECC–1). 

35NERC Petition at 5–6, 19–21; RFC Reply 

Comments at 15–16. 

36NERC defines direct control load management 

(DCLM) as ‘‘Demand-Side Management that is under 

the direct control of the system operator. DCLM 

may control the electric supply to individual 

appliances or equipment on customer premises. 

DCLM as defined here does not include 

Interruptible Demand.’’ Glossary of Terms Used in 

NERC Reliability Standards, April 20, 2010 (NERC 

Glossary), available at: http://www.nerc.com/docs/ 

standards/rs/Glossary_of_Terms_2010April20.pdf. 

37The NERC Glossary defines Interruptible Load 

as ‘‘Demand that the end-use customer makes 

available to its Load-Serving Entity via contract or 

agreements for curtailment.’’ 

38NOPR, FERC Stats. & Regs. ¶ 32,662 at P 18. 

just and reasonable manner through the 

imposition of the one day in ten years 

criterion for measuring resource 

adequacy. The Commission emphasizes 

that the one day in ten years criterion 

is one common approach for resource 

adequacy assessment, and by approving 

this regional Reliability Standard, the 

Commission does not establish the one 

day in ten years criterion to be the de 

facto, or the only acceptable metric for 

resource adequacy assessment. Rather, 

the Commission is acknowledging that 

the one day in ten years criterion is a 

well-established and common criterion 

for assessing resource adequacy.32 The 

use of a known and understood criterion 

should result in consistent, transparent 

and understandable resource adequacy 

analyses within the RFC region, and 

thus meets the reliability goal of 

establishing a common criterion to 

assess resource adequacy. 

32. The Commission does not disagree 

with commenters’ arguments that the 

one day in ten years criterion could be 

improved upon as an assessment tool or 

replaced with another methodology, but 

this does not mean that RFC’s proposed 

one day in ten years criterion is unjust 

or unreasonable. NERC endorsed the 

one day in ten years criterion in its 

Petition, stating that ‘‘experience has 

demonstrated that correlating generating 

capacity and customer load in a ‘loss of 

load’ methodology with a target of ‘one 

day in 10 year’ criterion has provided 

adequate generating capacity in real 

time operation * * * to supply all 

customer firm loads, even under 

extreme conditions.’’ 33 The Commission 

further notes that approving this 

regional Reliability Standard with the 

one day in ten years criterion does not 

prevent future changes or improvements 

to this resource assessment 

methodology. Our approval of BAL– 

502–RFC–02 does not prevent RFC or 

NERC from proposing other 

methodologies from replacing the one 

day in ten years criterion to assess 

resource adequacy and determine a 

level of planning reserve margin 

necessary to maintain reliability of the 

Bulk-Power System.34

33. The only obligations under BAL– 

502–RFC–02 are analysis and 

documentation requirements. This 

regional Reliability Standard does not 

specify how the results of the analysis 

required in this standard are to be used. 

For example, BAL–502–RFC–02 does 

not require state commissions to use the 

resource assessment analysis resulting 

from BAL–502–RFC–02 for economic 

decisions regarding resource adequacy 

requirements. Thus, the Commission 

rejects the Ohio PUC’s argument that the 

one day in ten years criterion is 

unreasonable because the criterion does 

not consider the economics of resource 

adequacy such as the cost of additional 

resources or the value of energy to the 

consumers whose service would be 

interrupted in the event of a shortfall. 

Certainly, the BAL–502–RFC–02 

assessments will be available as a tool 

to help inform the policy decisions to 

determine the level of service entities 

are willing to pay for and resource 

adequacy requirements. However, the 

Commission repeats, these activities are 

not required by this regional Reliability 

Standard. 

34. In response to the Ohio PUC’s 

claim that BAL–502–RFC–02 was 

developed with limited visibility to and 

involvement by many of those most 

involved in resource adequacy issues, 

e.g., state commissions and economists, 

the Commission emphasizes that BAL– 

502–RFC–02 was developed through an 

open and transparent process, allowing 

anyone with an interest to participate.35

As documented by RFC, during the 

standard development process, entities 

had multiple opportunities to express 

concerns regarding anything related to 

the regional Reliability Standard, 

including the one day in ten year 

criterion. The RFC Reliability Standards 

Development Procedure (RSDP) also 

includes an opportunity for submitting 

a ‘‘standard authorization request’’ to 

suggest a modification to any regional 

Reliability Standard or development of 

a new regional Reliability Standard. The 

Commission also notes that RFC will 

review BAL–502–RFC–02 at least every 

five years, thereby affording future 

opportunities for interested entities to 

participate in these reviews. 

B. Issues Regarding Specific BAL–502– 

RFC–02 Requirements 

35. In the NOPR, the Commission 

stated that it believes that the factors or 

characteristics to be considered in the 

resource adequacy analysis as set forth 

in Requirement R1 of BAL–502–RFC–02 

are a technically sound means to set up 

the analysis for ascertaining the 

probability of not having enough 

resources in order to meet demand and 

avoid loss of load. In addition, the 

Commission sought clarification 

regarding three aspects of the resource 

adequacy analysis: (i) The loss of load 

calculation, (ii) use of capacity benefit 

margin; and (iii) the meaning of 

common mode outages. 

1. Loss of Load Calculation 

36. Regional Reliability Standard 

BAL–502–RFC–02, Requirement R1.1 

states that the planning coordinator’s 

assessment shall calculate a planning 

reserve margin that results in the sum of 

probabilities for loss of load for each 

planning year equal to 0.1, or 

comparable to ‘‘one day in ten years’’ 

when available capacity will not meet 

the load. With respect to the loss of load 

calculation, BAL–502–RFC–02 

specifically identifies two 

circumstances that do not contribute to 

the loss of load probability: (1) 

Utilization of direct control load 

management 36 and (2) curtailment of 

interruptible load.37 Notwithstanding 

these two exceptions to the loss of load 

probability, the Commission sought 

comment on how other system operator 

actions, such as voltage reduction or 

other, non-voluntary types of load 

reduction plans, would be modeled and 

documented in this analysis.38

Comments 

37. RFC and Midwest ISO comment 

that real-time operating actions, like 

voltage reductions or other nonVerDate Mar<15>2010 15:27 Mar 22, 2011 Jkt 223001 PO 00000 Frm 00026 Fmt 4700 Sfmt 4700 E:\FR\FM\23MRR1.SGM 23MRR1

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39BAL–502–RFC–1, Requirement R1.3.1 sets 

forth the load forecast characteristics that are to be 

included and documented in the resource adequacy 

analysis. Specifically, Requirement R1.3.1 identifies 

the following six load forecast characteristics: (1) 

Median (50:50) forecast peak load; (2) load forecast 

uncertainty; (3) load diversity; (4) seasonal load 

variations; (5) daily demand modeling assumptions; 

and (6) contractual arrangements concerning 

curtailable/interruptible demand. 

40BAL–502–RFC–1, Requirement R1.4 requires 

the consideration in the resource adequacy analysis 

of eight resource availability characteristics and 

documentation of how and why they were included 

in the analysis or why they were not included. The 

resource availability characteristics include: (1) 

Availability and deliverability of fuel; (2) common 

mode outages that affect resource availability; (3) 

environmental or regulatory restrictions of resource 

availability; (4) any other demand (load) response 

programs not included in R1.3.1; (5) sensitivity to 

resource outage rates; (6) impacts of extreme 

weather/drought conditions that affect unit 

availability; (7) modeling assumptions for 

emergency operation procedures used to make 

reserves available; and (8) market resources not 

committed to serving load within the planning 

coordinator area. 

41NOPR, FERC Stats. & Regs. ¶ 32,662 at P 19. 

The NERC Glossary defines capacity benefit margin 

(CBM) as ‘‘the amount of firm transmission transfer 

capability preserved by the transmission provider 

for Load-Serving Entities (LSE), whose loads are 

located on that Transmission Service Provider’s 

system, to enable access by the LSEs to generation 

from interconnected systems to meet generation 

reliability requirements. Preservation of CBM for an 

LSE allows that entity to reduce its installed 

generating capacity below that which may 

otherwise have been necessary without 

interconnections to meet its generation reliability 

requirements. The transmission transfer capability 

preserved as CBM is intended to be used by the LSE 

only in times of emergency generation deficiencies.’’ 

Continued 

voluntary types of load reduction plans 

are not intended to be included in the 

BAL–502–RFC–02 assessment. RFC and 

Midwest ISO explain that these types of 

load reduction are only considered 

during the operating horizon and are not 

included in planning time frame 

assessments to comply with 

requirements associated with the 

planning horizon. 

38. Borlick, Midwest ISO, OCC, Ohio 

PUC and Wilson comment on various 

demand side resources and their 

inclusion or exclusion from the BAL– 

502–RFC–02 resource adequacy 

assessment. Borlick comments that price 

responsive demand should not be 

counted both in Requirement R1.3.1 

(load forecast characteristics) 39 and in 

Requirement R1.4 (resource availability 

characteristics).40 Midwest ISO states 

that the regional Reliability Standard 

does not limit which demand response 

programs are excluded from the loss of 

load calculation, thereby allowing for, 

not preventing, future innovations in 

demand side programs. OCC asserts that 

the NOPR and BAL–502–RFC–02 imply 

that voluntary curtailment services, 

including demand response, are 

completely excluded from consideration 

in the loss of load calculation. OCC 

further argues that complete exclusion 

of voluntary curtailment service from 

the loss of load calculation would 

undervalue demand response resources. 

OCC states that demand response 

resources should be taken into account 

in the loss of load calculation because 

they reduce the need for additional 

capacity. Accordingly, OCC urges the 

Commission to require including 

historical demand response rates for 

resources in the loss of load calculation. 

The Ohio PUC comments that price 

responsive demand is not accounted for 

in this regional Reliability Standard. 

Last, Wilson notes that approving BAL– 

502–RFC–02 could actually prevent 

demand response or price responsive 

demand from developing. 

Commission Determination 

39. Based on the Midwest ISO and 

RFC comments, the Commission accepts 

that for planning assessments conducted 

under BAL–502–RFC–02, typical system 

operator actions, such as voltage 

reduction or other non-voluntary types 

of load reduction plans should not be 

included given that they pertain to the 

operating, not planning, horizon. The 

Commission agrees with Borlick’s 

comment, and emphasizes that any type 

of demand response program, including 

price responsive demand, should not be 

represented twice in the assessment 

under both Requirement R1.3.1 and 

Requirement R1.4. The clause contained 

in Requirement R1.4 for considering 

‘‘Any other demand (Load) response 

programs not included in R1.3.1’’ 

(emphasis added) is sufficient to 

prevent any responsible entity from 

counting any type of demand response 

program multiple times within this 

assessment. 

40. The Commission also agrees with 

Midwest ISO’s comment that BAL–502– 

RFC–02’s requirements are not so 

restrictive that they would limit any 

specific types of demand response 

programs from being included in the 

BAL–502–RFC–02 assessment. Contrary 

to the comments from OCC, Ohio PUC 

and Wilson, the requirements for 

conducting the BAL–502–RFC–02 

assessment are general enough to 

include interruptible loads, voluntary 

curtailment services, price responsive 

demand, and other types of demand 

response programs, and therefore would 

not hinder the development of new 

programs or technologies related to 

demand-side resources. Regarding 

OCC’s comment that BAL–502–RFC–02 

completely excludes voluntary 

curtailment services from consideration 

in the loss of load calculation, thus 

undervaluing demand response, the 

Commission notes that demand 

response is addressed elsewhere in the 

assessment. While Requirement R1.1.1 

makes clear that utilization of direct 

control load management or curtailment 

of interruptible demand shall not 

contribute to the loss of load 

probability, Requirement R1.1.1 does 

not prevent demand related resources 

from being considered under other parts 

of the assessment, such as under 

Requirement R1.3.1 or R1.4. 

41. Specifically, the Commission 

agrees with OCC that historical demand 

response rates or performance should be 

considered in the BAL–502–RFC–02 

assessment to determine the 

effectiveness of a demand response 

program and typical performance 

achieved by the demand response 

program. Assessing how resources, 

including demand side resources, have 

performed in the past, how a resource’s 

performance changed over time, and 

how a resource’s performance varied 

under different scenarios is an effective 

way to estimate how the resource might 

perform under the conditions 

considered for the analysis. To that end, 

the Commission notes that BAL–502– 

RFC–02, Requirement R1.3.2 includes 

‘‘historical resource performance and 

any projected changes’’ as one of the 

resource characteristics to be considered 

in performing the resource adequacy 

analysis. Similarly, Requirement R1.4 

requires consideration of resource 

availability characteristics of ‘‘any other 

demand (Load) response programs not 

included in R1.3.1,’’ which could 

include historical performance of such 

demand response programs. 

Requirement R1.4 also requires the 

planning coordinator to document how 

and why each resource availability 

characteristic was included in the 

analysis, or why the characteristic was 

not included. 

42. Based on the foregoing, the 

Commission affirms that the loss of load 

calculation performed under 

Requirement R1.1 of BAL–502–RFC–02 

does not include typical system operator 

actions or non-voluntary types of load 

loss. The Commission further notes that 

demand response programs should be 

considered under aspects of a BAL– 

502–RFC–02 resource adequacy 

assessment, specifically under either 

R1.3.1 or R1.4 as appropriate. 

2. Use of Capacity Benefit Margin 

43. With respect to the capacity 

benefit margin (CBM), the Commission 

in the NOPR noted that the 

requirements do not explicitly state 

whether planning coordinators may rely 

upon CBM 41 to satisfy BAL–502–RFC– 


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Glossary of Terms Used in NERC Reliability 

Standards, April 20, 2010, available at: http:// 

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

Glossary_of_Terms_2010April20.pdf. 

42See NERC Petition, Exhibit C, Comments from 

ITC Transmission. 

43NOPR, FERC Stats. & Regs. ¶ 32,662 at P 19. 

Reliability Standard MOD–004–1 addresses CBM, 

or a capacity preserved for firm transmission 

transfer capability. Conversely, the Requirements in 

proposed Reliability Standard BAL–502–RFC–02 

address an analysis regarding the capability of 

generation to serve the projected load. While CBM 

could be a method of meeting the Requirements of 

BAL–502–RFC–02, the two Reliability Standards do 

not contradict each other. 

44NOPR, FERC Stats. & Regs. ¶ 32,662 at P 20. 

45Requirements R1.3.3 and R1.3.4 list items that 

must be considered in conducting the BAL–502– 

RFC–02 resource adequacy analysis. R1.3.3 refers to 

transmission limitations that prevent the delivery of 

generation reserves. R1.3.4 refers to assistance from 

other interconnected systems including multi-area 

assessment considering transmission limitations 

into the study area. 

46Time horizons are used as a factor in 

determining the size of a sanction. If an entity 

violates a Requirement and there is no time to 

mitigate the violation because the Requirement 

takes place in real-time, then, depending on the 

violation’s specific facts, the sanction associated 

with the violation generally would be higher than 

it would be for violation of a Requirement that 

could be mitigated over a longer period of time. See 

NERC’s ‘‘Time Horizons’’ document, available on 

NERC’s Web site at http://www.nerc.com/files/ 

Time_Horizons.pdf. 

47NERC Petition at 24. 

02’s requirements. During the standard 

development posting period, RFC 

received comments regarding potential 

conflicts or lack of coordination 

between BAL–502–RFC–02 and the 

continent-wide NERC Reliability 

Standard MOD–004–1—Capacity 

Benefit Margin.42 The Commission 

stated in the NOPR that it does not 

believe that BAL–502–RFC–02 conflicts 

with NERC Reliability Standard MOD– 

004–1. However, the Commission noted 

that there could be some confusion 

regarding whether CBM could or could 

not be used in order to meet the 

requirements of BAL–502–RFC–02,43

and sought comment on the issue. 

Comments 

44. Carden, Midwest ISO, RFC and 

Wilson responded to the Commission’s 

question regarding utilization of CBM to 

meet BAL–502–RFC–02’s requirements. 

Carden and Wilson support allowing 

CBM to be used to meet the 

requirements for the planning reserve 

margins. Midwest ISO comments that 

BAL–502–RFC–02 correctly neither 

excludes nor includes the use of CBM 

to meet the requirements. RFC states 

that CBM alone cannot satisfy the 

regional Reliability Standard. 

Commission Determination 

45. Based on these comments, the 

Commission understands and agrees 

that the intent of BAL–502–RFC–02 is 

that while CBM may be used to meet the 

requirements, it is not mandatory to 

include CBM in the assessment. The 

Commission also understands and 

agrees, as RFC stated, that CBM cannot 

be the only source assessed in order to 

satisfy BAL–502–RFC–02’s 

requirements. 

3. Meaning of Common Mode Outages 

46. With respect to Requirement R1.4, 

which requires the resource adequacy 

analysis to consider resource 

availability characteristics including 

‘‘common mode outages that affect 

resource availability,’’ the Commission 

sought comment on whether planning 

coordinators, when evaluating ‘‘common 

mode outages that affect resource 

availability’’ will consider only outages 

within the generation facility, or if the 

analysis will also consider outages of 

transmission facilities that would have 

an impact on resource or generator 

availability.44

Comments 

47. Both Midwest ISO and RFC agree 

that Requirement R1.4 only explicitly 

requires common mode outages of 

resources, but does not limit the 

consideration of transmission outages 

that could affect resource deliverability. 

Midwest ISO further explains that 

Requirements R1.3.3 and R1.3.4 45 apply 

to transmission facilities within and 

outside of the planning coordinator area 

and these requirements properly allow 

for the inclusion and documentation of 

consideration of common mode outages 

within a study, while not explicitly 

requiring the consideration of common 

mode outages. 

Commission Determination 

48. Based on the RFC and Midwest 

ISO comments, the Commission 

understands that common mode outages 

discussed in Requirement R1.4 do not 

explicitly require consideration of 

transmission facility outages. 

Notwithstanding that Requirement R1.4 

does not explicitly require consideration 

of transmission facility outages, the 

Commission agrees with the Midwest 

ISO that nothing in the standard limits 

a planning coordinator’s flexibility to 

consider such outages. 

49. Consistent with Midwest ISO 

comments, the Commission understands 

Requirements R1.3.3 and R1.3.4 apply 

to transmission facilities, specifically 

documenting transmission limitations 

that would prevent the delivery of 

generation reserves and considering 

transmission limitations impacting 

assistance from other interconnected 

systems. These transmission limitations 

could include, but do not explicitly 

require, outage assessments of 

transmission facilities that would result 

in preventing delivery of generation 

reserves. The Commission notes that the 

outage assessment would likely benefit 

from analyzing transmission facility 

outages that would directly impact the 

ability to deliver resources to demand, 

or decrease the amount of resources 

delivered to an area from interconnected 

systems. Not all transmission facilities 

would need to be included in the 

assessment as many individual 

transmission facilities would have 

minimal impact on resource 

deliverability. Thus, determining which 

transmission outages to assess would 

require some engineering judgment to 

determine the impact of the 

transmission outage on resource 

deliverability. The Commission 

encourages planning coordinators to 

consider transmission outages to 

determine which, if any, transmission 

outages have the greatest impact on 

delivery of resources and to include 

those limiting elements when evaluating 

common mode outages. 

C. Other Issues Raised in NOPR 

1. Missing Time Horizons 

50. The NERC Petition explained that 

the template for Reliability Standards 

dictates that each main requirement in 

a Reliability Standard be assigned one of 

the following time horizons: 46 (1) Longterm Planning (a planning horizon of 

one year or longer), (2) operations 

planning (operating and resource plans 

from day-ahead up to and including 

seasonal), (3) same-day operations 

(routine actions required within the 

timeframe of a day, but not real-time), 

(4) real-time operations (actions 

required within one hour or less to 

preserve the reliability of the bulk 

electric system), and (5) operations 

assessment (follow-up evaluations and 

reporting of real time operations). In the 

Petition, NERC noted the absence of a 

time horizon in BAL–502–RFC–02 and 

explained that RFC had stated that it did 

not include time horizons because its 

Commission-approved Reliability 

Standard Development Process does not 

include time horizons as a required 

element in its template for Reliability 

Standards. As stated in the NERC 

Petition, RFC also noted that ‘‘the [BAL– 

502–RFC–02] focuses on ‘planning 

oriented’ subject matter for one year and 

beyond,’’ and, as such, the appropriate 

time horizon, long-term planning, is 

relatively straight forward.47

51. In the NOPR, the Commission 

noted that it is important to identify the 


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48 Dominion notes that with respect to BAL–502– 

RFC–02, the stated effective date is ‘‘upon RFC 

Board approval,’’ which was December 4, 2008. 

However, under section 215 of the FPA, a 

Reliability Standard may not become effective until 

after Commission approval. 

49For this Final Rule, the effective date is 60 days 

after publication in the Federal Register. 

time horizons for each Reliability 

Standard, but acknowledged that time 

horizons are not critical to its 

determination of whether to approve a 

Reliability Standard. Moreover, the 

Commission agreed with RFC that with 

respect to BAL–502–RFC–02, the time 

horizon ‘‘long-term planning’’ can be 

gleaned from the context of the standard 

for the purpose of determining the 

severity of a violation risk factor, or for 

determining the penalty for a violation. 

Based on RFC’s statement that it is 

moving towards requiring the 

assignment of time horizons as part of 

its standard drafting process, the 

Commission proposed to direct RFC to 

add time horizons to the two main 

requirements when RFC reviews BAL– 

502–RFC–02 at the scheduled five-year 

review. 

Comments 

52. RFC states in its comments that it 

does not oppose the Commission’s 

proposal to direct RFC to add time 

horizons to BAL–502–RFC–02 during its 

scheduled five-year review. The only 

other commenter on the issue of time 

horizons, Midwest ISO, supports the 

NOPR’s proposal, noting that time 

horizons should be specifically 

identified in Reliability Standards 

because they are a factor for determining 

the size of a sanction. 

Commission Determination 

53. The Commission agrees with the 

Midwest ISO that time horizons are a 

factor in NERC’s determination of a 

penalty for a violation and 

acknowledges that RFC is modifying its 

standards development process such 

that it will include time horizons as an 

element in its regional Reliability 

Standards template. Accordingly, as 

proposed in the NOPR, the Commission 

directs RFC to add time horizons to the 

two main requirements when RFC 

reviews BAL–502–RFC–02 at the 

scheduled five-year review. 

2. Proposed Effective Date 

54. Proposed regional Reliability 

Standard BAL–502–RFC–02’s stated 

effective date is ‘‘upon RFC Board 

approval,’’ which occurred on December 

4, 2008. In the NOPR, the Commission 

noted that, while the effective date for 

Commission approved Reliability 

Standards is generally ‘‘the first day of 

the first quarter after regulatory 

approval,’’ with respect to BAL–502– 

RFC–02, no additional implementation 

time is necessary as the four registered 

planning coordinators in the RFC region 

are already subject to BAL–502–RFC–02 

by the terms of the RFC membership 

agreement. Accordingly, the 

Commission proposed in the NOPR that 

BAL–502–RFC–02 become mandatory 

and enforceable on the effective date of 

the Commission’s final rule approving 

the regional Reliability Standard. 

Comments 

55. Dominion is the sole commenter 

regarding the effective date. Dominion, 

noting the potential pitfalls that may 

occur when regions like RFC implement 

multiple effective dates for the same 

standard,48 seeks two clarifications. 

First, Dominion requests that the 

Commission clarify that the effective 

date of regional Reliability Standard 

BAL–502–RFC–02 is the effective date 

of the Commission’s final rule 

approving the standard and that the 

standard will be enforced prospectively 

only. Second, Dominion requests that 

the Commission clarify that all future 

regional Reliability Standards shall not 

have effective dates that are prior to the 

effective date of the Commission’s order 

approving the regional Reliability 

Standard and that RFC should modify 

its governance documents accordingly. 

Commission Determination 

56. Under section 215(d)(2) of the 

FPA, it is clear that a proposed 

Reliability Standard ‘‘shall take effect 

upon approval by the Commission.’’ 

Accordingly, a Reliability Standard 

cannot have an effective date in the 

United States that is prior to the 

effective date of the final rule issued by 

the Commission approving the 

Reliability Standard at issue. Thus, the 

effective date of BAL–502–RFC–02 is 

the effective date of this Final Rule, and 

further, BAL–502–RFC–02 first becomes 

enforceable upon this effective date.49

3. Provision of Data 

57. In the NOPR, the Commission, 

noting that BAL–502–RFC–02 does not 

require other entities (load-serving 

entities, balancing authorities, 

transmission operators, resource 

planners, or transmission planners) to 

provide the planning coordinators 

subject to BAL–502–RFC–02 the 

necessary data for the resource 

adequacy analysis, sought comment on 

whether the planning coordinators have 

encountered problems with collecting 

necessary data in order to complete the 

resource adequacy assessment that is 

the subject of BAL–502–RFC–02. 

Comments 

58. In response, both RFC and the 

Midwest ISO report that, to their 

knowledge planning coordinators have 

not had problems collecting the 

necessary data. 

Commission Determination 

59. Based on the comments of 

Midwest ISO and RFC, and the fact that 

no entity has raised a concern about the 

ability of RFC’s planning coordinators’ 

to obtain the data necessary to comply 

with BAL–502–RFC–02, we are satisfied 

that no action is necessary now on this 

issue. 

4. Consideration of Resources Beyond 

the RFC Footprint 

60. In the NOPR, the Commission 

sought comment on how to address load 

and resources outside of the RFC 

footprint during a planning assessment 

and on how entities currently perform 

this task or other similar planning tasks 

where load and resources are located 

outside of boundaries required by the 

assessment. 

Comments 

61. RFC states that current 

Requirements R1.3.4, R1.6 and R1.7 

address consideration of resources 

beyond the RFC footprint. Midwest ISO 

comments that while a common method 

for considering external support or 

modeling external systems appears 

beneficial, this would be an onerous 

task, and might limit valid 

methodologies for considering external 

support. Midwest ISO further comments 

that it considers resource adequacy on 

a footprint-wide basis, and includes 

resources outside of the RFC footprint, 

holding the entire Midwest ISO region 

to the ‘‘one day in ten years’’ criterion. 

Midwest ISO notes that if other regional 

entities develop potentially conflicting 

regional Reliability Standards, Midwest 

ISO could be subject to conflicting 

Reliability Standards for its planning 

coordinator footprint. 

Commission Determination 

62. The Commission agrees with 

RFC’s comment that Requirements 

R1.3.4, R1.6 and R1.7 are a means to 

address consideration of resources 

outside of the RFC footprint. By 

identifying what assistance from 

external areas is included in the 

assessment (R1.3.4) and what capacity 

resources and load are included within 

the planning coordinator area (R1.6 and 

R1.7), an entity can determine the area 

for which the assessment is being 

performed, and whether or not that area 

includes areas beyond the RFC 

footprint. The Commission agrees with 


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50For example, the PJM Manual 20: PJM Resource 

Adequacy Analysis, Section 3 provides ‘‘a guide for 

fostering consistency from year to year and across 

all related analysis,’’ and further describes input 

data and models, including what is identified as the 

PJM area and areas adjacent to PJM referred to as 

the ‘‘World.’’ See PJM Manual 20: PJM Resource 

Adequacy Analysis, Revision 3, 6/1/2007, at 17–28, 

available at http://www.pjm.com/documents/ 

manuals.aspx. 

51RFC Comment at 6. 

52We note that in Version Two Facilities Design, 

Connections and Maintenance Reliability 

Standards, Order No. 722, 126 FERC ¶ 61,255, at 

P 45 (2009), the ERO proposed to develop VRFs and 

VSLs for requirements but not sub-requirements. 

The Commission denied the proposal as 

‘‘premature’’ and, instead, encouraged the ERO to 

‘‘develop a new and comprehensive approach that 

would better facilitate the assignment of violation 

severity levels and violation risk factors.’’ As 

directed, on March 5, 2010, NERC submitted a 

comprehensive approach in Docket No. RR08–4– 

005, which is currently pending before the 

Commission. 

53NERC Petition at 24. 

54Borlick Comments at 7. 

55The specific definitions of high, medium and 

lower are provided in North American Electric 

Reliability Corp., 119 FERC ¶ 61,145, at P 9 (VRF 

Order), order on reh’g, 120 FERC ¶ 61,145 (2007) 

(VRF Rehearing Order). 

56The guidelines are: (1) Consistency with the 

conclusions of the Blackout Report; (2) consistency 

within a Reliability Standard; (3) consistency 

among Reliability Standards; (4) consistency with 

NERC’s definition of the violation risk factor level; 

and (5) treatment of requirements that com-mingle 

more than one obligation. See VRF Rehearing 

Order, 120 FERC ¶ 61,145 at P 8–13. 

Midwest ISO that identifying a common 

process for all planning coordinators to 

use might be onerous and might limit 

valid methodologies for determining 

whether or not to consider resources or 

loads outside of the RFC footprint when 

conducting the BAL–502–RFC–02 

resource adequacy assessment. 

However, the Commission expects that, 

as a foundational element of a reliability 

assessment, each planning coordinator 

would document its own consideration 

of resources and loads in the 

assessment.50

5. Planning Gap Identification 

63. In the NOPR, the Commission 

noted that BAL–502–RFC–02 does not 

include a requirement to document any 

gap between the planning reserve 

margin calculated in Requirement R1.1 

(the amount of planning reserve needed 

to ensure a ‘‘one day in ten years’’ 

criterion) and the actual planning 

reserve determined in the resource 

adequacy analysis. The Commission 

stated that it believes that it would be 

useful for planning coordinators to 

identify and document a deficiency in 

planning reserves to help ensure that 

entities are aware of potential risks 

regarding the capability to balance 

resources and demand in a planning 

timeframe. Accordingly, the 

Commission proposed to direct RFC, 

when reviewing BAL–502–RFC–02 

during its scheduled five-year review, to 

consider modifying BAL–502–RFC–02 

to include a new requirement to identify 

any gap between the needed amount of 

planning reserves defined in 

Requirement R1.1 and the planning 

reserves determined from the resource 

adequacy analysis. The Commission 

further clarified that this would be a 

documentation requirement only and 

would not require entities to install 

additional generation or transmission 

capacity. 

Comments 

64. RFC submitted the sole comment 

on this issue. RFC supports the proposal 

in the NOPR on this issue and stated 

that it ‘‘will consider modifying the 

Standard in its scheduled five-year 

review, to include a requirement to 

identify any gap between the needed 

amount of planning reserves defined in 

Requirement 1.1 and the planning 

reserves determined from the [Resource 

Adequacy] Analysis.’’ 51

Commission Determination 

65. The Commission accepts RFC’s 

commitment to consider, at the time of 

its five-year review, whether to add a 

requirement to BAL–502–RFC–02 that 

would require Planning Coordinators to 

identify any gap between the needed 

amount of planning reserves defined in 

Requirement R1.1 and the planning 

reserves determined from the resource 

adequacy analysis. 

D. Regional Definitions 

66. Regional Reliability Standard 

BAL–502–RFC–02 includes four new 

defined terms that apply only to the 

RFC region: Resource Adequacy, Net 

Internal Demand, Peak Period, and Year 

One. In the NOPR, the Commission 

proposed to accept the four new defined 

terms to be applicable only in the RFC 

region. 

Comments 

67. No comments were filed regarding 

the four regional definitions. 

Commission Determination 

68. The Commission approves the 

inclusion of the four new regional 

definitions related to BAL–502–RFC–02 

in the NERC Glossary, specifically as 

RFC regional terms. 

E. Violation Risk Factors/Violation 

Security Levels 

69. With respect to BAL–502–RFC–02, 

RFC assigned VRFs only to the two 

main requirements and did not propose 

VRFs for any of the sub-requirements.52

RFC assigned Requirement R1 a 

‘‘medium’’ VRF and Requirement R2 a 

‘‘lower’’ VRF. Requirement R1 is 

assigned a ‘‘medium’’ VRF based on RFC 

and NERC’s conclusion that it is a 

Requirement in a planning time frame 

and, if violated, could affect the 

capability of the Bulk-Power System. 

Requirement R2 is assigned a ‘‘lower’’ 

VRF because it is a documentation only 

requirement and therefore is considered 

to be administrative. Similarly, RFC 

assigned VSLs only to the main 

Requirements, R1 and R2, of proposed 

BAL–502–RFC–02, and not to any of the 

sub-requirements. NERC notes that 

RFC’s assignment of VRFs and VSLs 

only to the main requirements is 

consistent with NERC’s ‘‘roll-up’’ 

proposal in its August 10, 2009 

Informational Filing Regarding the 

Assignment of VRFs and VSLs.53 NERC 

also stated that RFC followed applicable 

NERC and FERC guidance in developing 

the VSLs and VRFs for BAL–502–RFC– 

02. 

70. In the NOPR, the Commission 

proposed deferring action on the 

proposed VRFs and VSLs assigned to 

BAL–502–RFC–02 until after the 

Commission acts on NERC’s pending 

petition in Docket No. RR08–4–005, in 

which NERC proposes a ‘‘roll-up’’ 

approach for VRF and VSL assignments 

by which NERC would only assign VRFs 

and VSLs to the main requirements and 

not to the sub-requirements. 

Comments 

71. Borlick and Midwest ISO 

comment on the VRF and VSL 

assignments. The Midwest ISO states 

that the VRF for Requirement R1 should 

be assigned a lower VRF because 

Requirement R1 will never directly 

affect the electrical state of the RFC 

Region. Borlick makes a generic 

comment regarding VSLs, stating that 

‘‘the assignment of qualitative [VSLs] to 

various infractions is too ‘fluffy’.’’ 54

Commission Determination 

72. A VRF is assigned to 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. VRFs are either: Lower, 

medium or high.55 The Commission has 

established guidelines for evaluating the 

validity of each VRF assignment.56

73. NERC will also define up to four 

VSLs (low, moderate, high, and severe) 

as measurements for the degree to 

which the requirement was violated in 

a specific circumstance. For a specific 

violation of a particular Requirement, 

NERC or the Regional Entity will 


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57North American Electric Reliability Corp., 123 

FERC ¶ 61,284, at P 20–35 (VSL Order), order on 

reh’g & compliance, 125 FERC ¶ 61,212 (2008). The 

VSL guidelines are: (1) VSL assignments should not 

have the unintended consequence of lowering the 

current level of compliance; (2) the VSL should 

ensure uniformity and consistency in the 

determination of penalties; (3) a VSL assignment 

should be consistent with the corresponding 

requirement; and (4) a VSL assignment should be 

based on a single violation, not on a cumulative 

number of violations. 

58The VRF Order guidance emphasizes 

consistency with NERC’s definition of the VRF 

level. NERC defines a ‘‘medium’’ risk requirement, 

which will be assigned a medium VRF, as follows: 

‘‘A requirement that, if violated, could directly 

affect the electrical state or the capability of the 

bulk electric system, or the ability to effectively 

monitor and control the bulk electric system. 

However, violation of a medium risk requirement 

is unlikely to lead to bulk electric system 

instability, separation, or cascading failures; or, a 

requirement in a planning time frame that, if 

violated, could, under emergency, abnormal, or 

restorative conditions anticipated by the 

preparations, directly and adversely affect the 

electrical state or capability of the bulk electric 

system, or the ability to effectively monitor, control, 

or restore the bulk electric system. * * *.’’ NERC 

Violation Risk Factor, available at http:// 

www.nerc.com/files/Violation_Risk_Factors.pdf. 

59 44 U.S.C. 3507(d). 

60 5 CFR 1320.11. 

61See RFC’s Planning Resource Adequacy 

Analysis, Assessment and Documentation 

Implementation Plan, available online at https:// 

rsvp.rfirst.org/BAL502RFC02/ 

SupportingDocuments/BAL–502–RFC– 

02_Implementation_Plan.pdf. 

establish the initial value range for the 

base penalty amount by finding the 

intersection of the applicable VRF and 

VSL in the base penalty amount table in 

Appendix A of its sanction guidelines. 

On June 19, 2008, the Commission 

issued an order establishing four 

guidelines for the development of 

VSLs.57

74. The Commission has reviewed the 

VRF and VSL assignments for BAL– 

502–RFC–02 and it is our view that both 

the VRFs and VSLs are consistent with 

the above-described Commission 

guidance. The Commission does not 

agree with Midwest ISO that 

Requirement R1 should be assigned a 

‘‘lower’’ VRF instead of ‘‘medium.’’ 

Midwest ISO states that the VRF for 

Requirement R1 should be ‘‘lower’’ 

because Requirement R1: (1) Will never 

directly affect the electrical state or 

capability of the bulk electric system, 

and (2) only establishes administrative 

requirements to conduct an analysis 

without compelling planning 

coordinators to take actions based upon 

the analysis. The Commission finds that 

Requirement R1 is not administrative in 

nature as it requires an analysis of the 

state of the Bulk-Power System in the 

planning horizon to be able to meet 

demand with available resources. While 

this standard does not specifically 

require planning coordinators to take 

action per the results of this analysis, 

not performing the analysis would 

create a lack of awareness of the BulkPower System’s ability to meet demand 

with available resources during the 

planning horizon, which, if no actions 

were taken, could directly affect the 

electrical state or capability of the BulkPower System. Thus, the nature of 

Requirement R1 is consistent with 

NERC’s definition of a ‘‘medium’’ VRF 

level rather than the ‘‘lower’’ level.58

75. With respect to Borlick’s comment 

that the assignment of qualitative VSLs 

to various infractions is too ‘‘fluffy,’’ the 

Commission finds this to be a generic 

concern regarding VSLs that is outside 

the scope of this proceeding. 

76. Accordingly, the Commission 

approves the VRFs and VSLs assigned to 

the two main Requirements in BAL– 

502–RFC–02. Although the Commission 

is approving the VRFs and VSLs, which 

are assigned only to the main 

Requirements of the Reliability 

Standard, the Commission is not making 

any determination regarding NERC’s 

and RFC’s decision to apply its 

proposed ‘‘roll-up’’ approach to BAL– 

502–RFC–02, i.e., to not assign VRFs 

and VSLs to any Sub-requirement. The 

appropriateness of the roll-up approach 

is pending before the Commission in 

Docket No. RR08–4–005. 

III. Information Collection Statement 

77. The following collections of 

information contained in this proposed 

rule have been submitted to the Office 

of Management and Budget (OMB) for 

review under section 3507(d) of the 

Paperwork Reduction Act of 1995.59

OMB’s regulations require OMB to 

approve certain information collection 

requirements imposed by agency rule.60

Upon approval of a collection(s) of 

information, OMB will assign an OMB 

control number and an expiration date. 

Respondents subject to the filing 

requirements of an agency rule will not 

be penalized for failing to respond to 

these collections of information unless 

the collections of information display a 

valid OMB control number. 

78. The Commission solicited 

comments on the need for and the 

purpose of the information contained in 

regional Reliability Standard BAL–502– 

RFC–02 and the corresponding burden 

to implement it. The Commission 

received comments on specific 

Requirements in the regional Reliability 

Standard, which we address in this 

Final Rule. However, we did not receive 

any comments on our reporting burden 

estimates. The Commission has not 

directed any immediate modifications to 

the Requirements in the regional 

Reliability Standard being approved. 

Thus, the Final Rule does not affect the 

burden estimate provided in the NOPR. 

Burden Estimate: Regional Reliability 

Standard BAL–502–RFC–02 requires 

planning coordinators within the RFC 

geographical footprint to analyze, assess 

and document resource adequacy, 

annually, and to document and post 

projected load and resource capability 

in each area and transmissionconstrained sub-area identified in the 

resource adequacy assessment. BAL– 

502–RFC–02, which applies to four 

planning coordinators located in the 

eastern portion of the U.S., does not 

require the planning coordinators to file 

information with the Commission. It 

does require planning coordinators to 

develop, document, publically post, and 

retain certain information, subject to 

compliance monitoring by RFC. 

However, the Commission does not 

believe that approval of BAL–502–RFC– 

02 will result in a substantive increase 

in reporting burdens because the 

Reliability Standard implements the 

current, mandatory and enforceable 

practices in RFC. As RFC has 

represented, the affected RFC-member 

planning coordinators have been subject 

to these requirements since December 

2008 and would continue to be subject 

to them even if the Commission did not 

approve BAL–502–RFC–02 as a regional 

Reliability Standard subject to 

Commission, NERC and RFC 

enforcement under section 215 of the 

FPA. As stated in the RFC’s 

implementation plan for BAL–502– 

RFC–02, once this standard was 

approved by RFC’s Board of Trustees, 

which occurred on December 4, 2008, 

the requirements under the standard 

became effective with respect to RFC 

members and subject to the enforcement 

mechanism under the ‘‘Term of 

Membership’’ in RFC’s by-laws.61 Thus, 

the Commission finds that the 

requirements to develop, document, and 

maintain information in the regional 

Reliability Standard are current and 

ongoing requirements for RFC members 

and, therefore, the Commission’s 

proposed action in this Final Rule 

would not impose any additional 

burden on RFC-member planning 

coordinators. The proposed regional 

Reliability Standard is a new standard 

and was not included in the original 

standards submitted for review and 

approval by OMB. In addition, 

Commission approval of proposed 

regional Reliability Standard BAL–502– 

RFC–02 makes the standard mandatory 

and enforceable. Therefore, the 


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16262 Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 

62At this time, there are only four registered 

planning coordinators in the RFC region. 

63Regulations Implementing the National 

Environmental Policy Act of 1969, Order No. 486 

52 FR 47,897 (Dec. 17, 1987), FERC Stats. & Regs., 

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

64 18 CFR 380.4(a)(2)(ii). 

65 5 U.S.C. 601–612. 

66 13 CFR 121.101. 

67 13 CFR 121.201, Sector 22, Utilities & n. 1. 

Commission will submit this final rule 

to OMB for review and approval of the 

reporting requirements and propose a de 

minimis burden to reflect the prior 

implementation by RFC as part of its 

region’s standard practices. 

79. The Commission estimates that 

the increased Public Reporting Burden 

of approving BAL–502–RFC–02 is de 

minimis as follows: 

Proposed data collection FERC–725–H Number of 

respondents 

Number of 

responses 

Hours per 

respondent 

Total annual 

hours 

Registered planning coordinators 62 in the RFC region .................. 4 1 10 40 

Total .......................................................................................... ............................ ............................ ............................ 40 

Information Collection Costs: 

• Total annual costs: $2,651.41 ((40 

hours/2080 hours/year) × $137,874/ 

year). 

• Title: FERC–725–H, RFC Regional 

Reliability Standard. 

• Action: Collection of information. 

• OMB Control No: To be determined. 

• Respondents: Registered planning 

coordinators in the RFC region. 

• Frequency of Responses: On 

occasion. 

• Necessity of the Information: This 

Final Rule approves a regional 

Reliability Standard that requires 

planning coordinators to document and 

maintain, for the current and prior two 

years, their resource adequacy analyses 

and the projected load and resource 

capability subject to review by the 

Commission, NERC, and RFC to ensure 

compliance with the regional Reliability 

Standard. 

• Internal review: The Commission 

has reviewed the regional Reliability 

Standard BAL–502–RFC–02 and 

determined that the standard’s 

Requirements are necessary to meet the 

statutory provisions of the Energy Policy 

Act of 2005. The Commission has 

assured itself, by means of internal 

review, that there is specific, objective 

support for the burden estimates 

associated with the information 

requirements. 

80. 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 

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 FERC–725H and the docket 

number of this final rule in your 

submission. 

IV. Environmental Analysis 

81. 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.63 The Commission has 

categorically excluded certain actions 

from this requirement as not having a 

significant effect on the human 

environment. Included in the exclusion 

are rules that are clarifying, corrective, 

or procedural or that do not 

substantially change the effect of the 

regulations being amended.64 The 

actions taken in this Final Rule fall 

within this categorical exclusion as the 

regional Reliability Standard reflects a 

continuation of existing resource 

planning assessment requirements for 

these planning coordinators and is 

‘‘new’’ only with respect to the fact that 

once approved by the Commission, it 

will be subject to enforcement by RFC, 

NERC or the Commission. Accordingly, 

neither an environmental impact 

statement nor environmental assessment 

is required. 

V. Regulatory Flexibility Act 

Certification 

82. The Regulatory Flexibility Act of 

1980 (RFA) 65 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.66 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.67 The 

entities to which the requirements of 

this Rule would apply, i.e., planning 

coordinators within the RFC region, do 

not fall within the definition of small 

entities. Moreover, the regional 

Reliability Standard reflects a 

continuation of existing resource 

planning assessment requirements for 

these planning coordinators and is 

‘‘new’’ only with respect to the fact that 

once approved by the Commission, it 

will be subject to enforcement by RFC, 

NERC or the Commission. Based on the 

foregoing, the Commission certifies that 

this Rule will not have a significant 

impact on a substantial number of small 

entities. Accordingly, no regulatory 

flexibility analysis is required. 

VI. Document Availability 

83. 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. 

84. 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. 

85. User assistance is available for 

eLibrary and the FERC’s Web site during 


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Federal Register / Vol. 76, No. 56 / Wednesday, March 23, 2011 / Rules and Regulations 16263 

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 

86. These regulations, including 

regional Reliability Standard BAL–502– 

RFC–02, 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. 

By the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

Appendix A: Entities That Filed 

Comments, Motions To Intervene or 

Notices of Intervention 

Abbreviation Commenter 

Commenters 

Dominion .......................................................................................................... Dominion Resources Services, Inc. 

Carden ............................................................................................................. Kevin Carden, Johannes Pfeifenberger, and Nick Wintermantel. 

ICC ................................................................................................................... Illinois Commerce Commission. 

Midwest ISO .................................................................................................... Midwest Independent Transmission System Operator, Inc. 

MRO ................................................................................................................. Midwest Reliability Organization. 

NARUC ............................................................................................................ National Association of Regulatory Utility Commissioners. 

NERC ............................................................................................................... North American Electric Reliability Corporation+. 

OCC ................................................................................................................. Office of the Ohio Consumers’ Counsel. 

OMS ................................................................................................................. Organization of MISO States. 

Ohio PUC ......................................................................................................... Public Utilities Commission of Ohio. 

PJM Power Providers ...................................................................................... PJM Power Providers Group. 

RFC .................................................................................................................. ReliabilityFirst Corporation+. 

Borlick .............................................................................................................. Robert L. Borlick. 

Wilson .............................................................................................................. James F. Wilson. 

Intervenors 

Constellation Energy Commodities Group, Inc.

Dayton Power and Light Company.

Designated FirstEnergy Affiliates*.

Exelon Corp.

New York State Public Service Commission.

Pennsylvania Public Utility Commission.

PSEG Companies.

Public Utilities Commission of the State of California.

+ NERC and RFC filed both comments and reply comments. 

* The Designated FirstEnergy Affiliates include: Ohio Edison Co., Cleveland Electric Illuminating Co., Pennsylvania Power Co., Toledo Edison 

Co., American Transmission Systems, Inc., Jersey Central Power & Light Co., Metropolitan Edison Co., Pennsylvania Electric Co., and 

FirstEnergy Solutions Corp. 

[FR Doc. 2011–6763 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. RM09–18–001; Order No. 743– 

A] 

Revision to Electric Reliability 

Organization Definition of Bulk Electric 

System 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Order on rehearing. 

SUMMARY: The Commission denies 

rehearing and otherwise reaffirms its 

determinations in Order No. 743. In 

addition, the Commission clarifies 

certain provisions of the Final Rule. 

Order No. 743 directed the Electric 

Reliability Organization (ERO) to revise 

the definition of the term ‘‘bulk electric 

system’’ through the ERO’s Reliability 

Standards Development Process to 

address the Commission’s policy and 

technical concerns and ensure that the 

definition encompasses all facilities 

necessary for operating an 

interconnected electric transmission 

network pursuant to section 215 of the 

Federal Power Act. 

DATES: Effective Date: This order on 

rehearing and clarification will become 

effective March 23, 2011. 

FOR FURTHER INFORMATION CONTACT: 

Robert V. Snow (Technical Information), 

Office of Electric Reliability, Division 

of Reliability Standards, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426. Telephone: (202) 502–6716. 

Patrick A. Boughan (Technical 

Information), Office of Electric 

Reliability, Division of Engineering, 

Planning and Operations, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426. Telephone: (202) 502–8071. 

Jonathan E. First (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426. Telephone: (202) 502–8529. 

Mindi Sauter (Legal Information), Office 

of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 

20426. Telephone: (202) 502–6830. 

SUPPLEMENTARY INFORMATION: 

Before Commissioners: Jon Wellinghoff, 

Chairman; Marc Spitzer, Philip D. Moeller, 

John R. Norris, and Cheryl A. LaFleur. 

I. Order on Rehearing 

Issued March 17, 2011. 

I. Introduction 

1. On November 18, 2010, the 

Commission issued a Final Rule (Order 


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