66038 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Proposed Rules 

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

2North American Electric Reliability Corp., 116 

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

reh’g and 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). 

4 Id. at 824o(a)(7) and (e)(4). 

5Rules Concerning Certification of the Electric 

Reliability Organization; and 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). 

6Order No. 672, FERC Stats. & Regs. ¶ 31,204 at 

P 291. 

7See 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). 

8 Id. P 339 (clarifying that the RFC Standards 

Development Manual embodies ‘‘rules’’ which are 

subject to NERC approval and, if approved by 

NERC, Commission approval). 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket No. RM10–10–000] 

Planning Resource Adequacy 

Assessment Reliability Standard 

Issued October 21, 2010. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Notice of proposed rulemaking. 

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

Federal Power Act (FPA), the Federal 

Energy Regulatory Commission 

proposes to approve a 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 proposed 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 

year’’ loss of load criterion, and to 

document and post load and resource 

capability in each area or transmissionconstrained sub-area identified. 

DATES: Comments are due December 27, 

2010. 

ADDRESSES: You may submit comments, 

identified by docket number and in 

accordance with the requirements 

posted on the Commission’s Web site, 

http://www.ferc.gov. Comments may be 

submitted by any of the following 

methods: 

• Electronic Submission: Documents 

created electronically using word 

processing software should be filed in 

native applications or print-to-PDF 

format, and not in a scanned format, at 

http://www.ferc.gov/docs-filing/ 

efiling.asp. 

• Mail/Hand Delivery: Commenters 

unable to file comments electronically 

must mail or hand deliver an original 

copy of their comments to: Federal 

Energy Regulatory Commission, 

Secretary of the Commission, 888 First 

Street, NE., Washington, DC 20426. 

These requirements can be found on the 

Commission’s Web site, see, e.g., the 

‘‘Quick Reference Guide for Paper 

Submissions,’’ available at http:// 

www.ferc.gov/docs-filing/efiling.asp, or 

via phone from FERC Online Support at 

202–502–6652 or toll-free at 1–866– 

208–3676. 

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: 

Notice of Proposed Rulemaking 

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

Federal Power Act (FPA), the Federal 

Energy Regulatory Commission 

proposes to approve a 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 proposed 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 

year’’ loss of load criterion, and to 

document and post load and resource 

capability in each area or transmissionconstrained sub-area identified. 

I. Background 

A. Mandatory Reliability Standards 

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

3. Reliability Standards that the ERO 

proposes to the Commission may 

include Reliability Standards that are 

developed by a Regional Entity.3 A 

Regional Entity is an entity that has 

been approved by the Commission to 

enforce Reliability Standards under 

delegated authority from the ERO.4 In 

Order No. 672, the Commission urged 

uniformity of Reliability Standards, but 

recognized a potential need for regional 

differences.5 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.6

4. Consistent with section 215 of the 

FPA, the Commission will approve 

proposed regional Reliability Standard 

BAL–502–RFC–02 if the Commission 

finds it is just, reasonable, not unduly 

discriminatory or preferential, and in 

the public interest. 

B. ReliabilityFirst 

5. On April 19, 2007, the Commission 

approved delegation agreements 

between NERC and eight Regional 

Entities.7 Pursuant to such agreements, 

the ERO delegated responsibility to the 

Regional Entities to enforce the 

mandatory, Commission-approved 

Reliability Standards. In addition, the 

Commission approved, as part of each 

delegation agreement, a Regional Entity 

process for developing regional 

Reliability Standards. 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.8 The RFC region 

is a less than interconnection-wide 

region that covers all or portions of 14 

states and the District of Columbia. 

II. RFC Regional Reliability Standard 

BAL–502–RFC–02 

6. On December 14, 2009, NERC 

submitted for Commission approval, in 

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


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9 16 U.S.C. 824o. 

10NERC Petition for Approval of Proposed RFC 

Regional Reliability Standard BAL–502–RFC–02, 

Docket No. RM10–10–000 (Dec. 14, 2009) (Petition). 11NERC Petition at 7. 12 Id. at 7. NERC notes that it has a pending 

continent-wide project, Project 2009–05, Resource 

Adequacy Assessments, that is intended to address 

resource adequacy assessments. This NERC project 

has a targeted completion date of third quarter 

2011. 

13According to the RFC April 16, 2010 

organization registration (available at http:// 

rfirst.org/Compliance/Registration.aspx), there are 

four registered planning coordinators in the RFC 

region, each of which is a RFC member. See RFC’s 

January 11, 2010 list of member companies by 

sector, available at http://rfirst.org/MiscForms/ 

AboutUs/Membership.aspx. The four registered 

planning coordinators are American Transmission 

Co., LLC; International Transmission Company (ITC 

Transmission); Midwest Independent Transmission 

System Operator, Inc. (Midwest ISO); and PJM 

Interconnection, LLC (PJM). 

14NERC notes that the proposed Reliability 

Standard does not require the building or 

acquisition of new generating capacity. See NERC 

Petition at 9. 

15The NERC Glossary (updated Apr. 20, 2010) is 

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

rs/Glossary_of_Terms_2010April20.pdf. 

16Order No. 672, FERC Stats. & Regs. ¶ 31,204 at 

P 323–337. 

17NERC’s Glossary lists each term that has been 

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

18Reliability Standard TOP–002–2a, Requirement 

R7. 

19 Mandatory Reliability Standards for the BulkPower System, Order No. 693, FERC Stats. & Regs. 

¶ 31,242, at P 1590, order on reh’g, Order No. 693– 

A, 120 FERC ¶ 61,053 (2007). See also the Notice 

of Proposed Rulemaking, Docket No. RM06–16–000, 

FERC Stats. & Regs., Proposed Regulations 2004– 

2007, ¶ 32,608 (2006) (Order No. 693 NOPR). 

FPA,9 regional Reliability Standard 

BAL–502–RFC–02 and four associated 

new definitions.10 The stated purpose of 

regional Reliability Standard BAL–502– 

RFC–02 is to establish common criteria, 

based on ‘‘one day in ten year’’ loss of 

load expectation principles, for the 

analysis, assessment and documentation 

of resource adequacy in the RFC 

region.11 NERC states 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.12

7. Proposed regional Reliability 

Standard BAL–502–RFC–02 contains 

two Requirements, which are applicable 

to each planning coordinator within the 

RFC footprint.13 Requirement R1 

requires each planning coordinator to 

perform and document an annual 

resource adequacy analysis.14 The seven 

Sub-requirements define the criteria to 

be used for the resource adequacy 

analysis. Sub-requirement R1.1 sets 

forth the ‘‘one day in ten year’’ criteria 

to be used to calculate the planning 

reserve margin. Sub-requirement R1.2 

specifies the planning years to be 

studied. Sub-requirement R1.3 defines 

system characteristics to be included in 

the analysis. Sub-requirements R1.4 and 

R1.5 require the consideration of 

resource availability and transmission 

outage plans. Sub-requirements R1.6 

and R1.7 require documentation that 

capacity resources and load were 

properly accounted for in the 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. Sub-requirements R2.1 through 

R2.3 set forth the specific 

documentation requirements. Each of 

the main Requirements (R1 and R2) are 

assigned a violation risk factor (VRF) 

and violation severity level (VSL). 

However, RFC did not assign VRFs or 

VSLs to the Sub-requirements. 

8. NERC also proposes to add the 

following four new definitions, which 

would be applicable in the RFC region 

only: 

Resource Adequacy: The ability of supplyside and demand-side resources to meet the 

aggregate electrical demand (including 

losses). 

Net Internal Demand: Total of all end-use 

customer demand and electric system losses 

within specified metered boundaries, less 

Direct Control Load Management and 

Interruptible Demand. 

Peak Period: 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. 

Year One: The planning year that begins 

with the upcoming annual Peak Period. 

NERC states that these four terms do 

not presently appear in the NERC 

Glossary of Terms Used in Reliability 

Standards (Glossary) and they do not 

conflict with existing terms.15

9. NERC states that on February 24, 

2009, RFC submitted the proposed 

Reliability Standard to NERC for 

evaluation and approval. On April 17, 

2009, NERC provided RFC its evaluation 

of BAL–502–RFC–02 which highlighted 

several concerns regarding the proposed 

standard. NERC’s concerns included: (1) 

Missing time horizons, (2) effective date 

not meeting NERC’s template language, 

(3) complex sub-requirements, (4) the 

addition of new defined terms, (5) the 

assignment of VRFs and VSLs only to 

the Reliability Standard’s two main 

Requirements and not the subrequirements, and (6) technical clarity. 

On June 8, 2009, RFC submitted a 

response to NERC addressing NERC’s 

concerns. 

10. NERC concludes that the proposed 

RFC regional Reliability Standard 

addresses matters not currently covered 

in a continent-wide NERC Reliability 

Standard and thus meets the 

Commission’s criteria for consideration 

of a regional Reliability Standard. NERC 

asserts that the proposed regional 

Reliability Standard satisfies all of the 

criteria set forth in Order No. 672 that 

the Commission applies to determine 

whether a proposed Reliability Standard 

is just, reasonable, not unduly 

discriminatory or preferential and in the 

public interest.16 As such, NERC 

requests approval of proposed regional 

Reliability Standard BAL–502–RFC–02 

and the related definitions. 

III. Discussion 

11. As discussed below, the 

Commission proposes to approve BAL– 

502–RFC–02. The proposed regional 

Reliability 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 year’’ principle, to assess 

resource adequacy during the planning 

horizon. The Commission also proposes 

to accept the four related definitions for 

inclusion in NERC’s Glossary for use 

with RFC’s regional Reliability 

Standards.17 The Commission further 

proposes to defer discussion on the 

proposed VRFs and VSLs for the 

regional Reliability Standard. 

12. Proposed regional Reliability 

Standard BAL–502–RFC–02 is ‘‘more 

stringent’’ in that NERC’s continentwide standards currently do not address 

assessment of Resource Adequacy in the 

planning horizon. The Commission 

notes the current continent-wide 

Reliability Standard TOP–002–2a, 

Requirement R7 requires Balancing 

Authorities to plan to meet capacity and 

energy reserve requirements, including 

the deliverability/capability for any 

single contingency.18 Reliability 

Standard TOP–002–2 ensures that 

resources and operational plans are in 

place to enable system operators to 

maintain the Bulk-Power System in a 

reliable state.19 Thus Reliability 

Standard TOP–002–2 is a continentwide Reliability Standard that addresses 

requirements for reserves during the 

operations timeframe whereas proposed 

regional Reliability Standard BAL–502– 

RFC–02 addresses the assessment of 

resource adequacy (or planning 

reserves) during the planning 

timeframe. If NERC develops a 

continent-wide Reliability Standard that 

addresses assessment of resource 

adequacy in the planning horizon and 

such Reliability Standard is approved 

by the Commission, RFC should 


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20Order No. 672, FERC Stats. & Regs. ¶ 31,204 at 

P 324. 21 Id. 22See proposed Reliability Standard BAL–502– 

RFC–02, Requirement R1.2. 

23See id. at Requirement R1.1. 

24See id. at Requirement R1.1.2 n.2. 

25See id. at Requirement R1.3.1. 

26See id. at Requirements R1.7. 

27See id. at Requirements R1.3.1, R1.3.2, and 

R1.3.3. 

28See id. at Requirements R1.3.2 and R1.4. 

29See id. at Requirement R1.6. 

30See id. at Requirements R1.3.3, R1.3.3.1, 

R1.3.3.2 and R1.5. 

31NERC 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.’’ 

32NERC defines Interruptible Load as ‘‘Demand 

that the end-use customer makes available to its 

Load-Serving Entity via contract or agreements for 

curtailment.’’ 

reevaluate the continuing need for 

regional Reliability Standard BAL–502– 

RFC–02. 

A. Order No. 672 Criteria 

13. Order No. 672 provides that a 

Reliability Standard must be designed to 

achieve a specified reliability goal and 

must contain a technically sound means 

to achieve this goal.20 Likewise, the 

Reliability Standard should be based on 

actual data and lessons learned from 

actual operations.21 According to NERC 

and RFC, proposed regional Reliability 

Standard BAL–502–RFC–02 is clear and 

unambiguous regarding what is required 

and who is required to comply 

(planning coordinator). NERC and RFC 

also state that BAL–502–RFC–02 has 

clear and objective measures for 

compliance and achieves a reliability 

goal (namely, providing a common 

framework for resource adequacy 

analysis, assessment, and 

documentation) effectively and 

efficiently. Based on the Commission’s 

understanding of the proposed regional 

Reliability Standard, explained below, 

the Commission believes that BAL–502– 

RFC–02 satisfies the Order No. 672 

criteria. 

B. RFC’s Proposed Resource Adequacy 

Reliability Standard Requirements 

14. Proposed 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 year’’ 

criterion. 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.22 The regional 

Reliability Standard further requires the 

planning coordinators to calculate the 

planning reserve margin by assessing 

each of the integrated peak hours for 

each day within the year being analyzed 

to determine the probability that 

generation and demand-side resources 

cannot meet the demand during that 

hour for that day (which would result in 

a loss of load).23 The calculated 

planning reserve margin is to be 

expressed as a percentage of the median 

forecast peak demand (not including 

direct control load management and 

interruptible demand). Regional 

Reliability Standard BAL–502–RFC–02 

states that this median forecast is 

expected to have a 50 percent 

probability that the projected load is too 

high and 50 percent probability that the 

projected load is too low.24 In order to 

determine the appropriate load forecast, 

the planning coordinators must consider 

multiple factors including: 

(i) Variability in the load forecast such 

as weather and regional economic 

forecasts, (ii) load diversity, 

(iii) seasonal load variations, (iv) firm 

load and (v) interruptible load including 

contractual arrangements concerning 

curtailable and/or interruptible 

demand.25 In addition, the planning 

coordinator must document that all load 

in its area is accounted for in the 

analysis.26

15. Further, the planning coordinator 

must determine the probability of 

resources that will be online and 

available, determine the distribution of 

the peak load for each day, and include 

impacts of known transmission 

limitations.27 To determine the 

probability of available resources the 

planning coordinator must consider 

multiple factors. Such factors include: 

(i) The historic resource performance, 

(ii) seasonal resource ratings, (iii) firm 

capacity purchases from and sales to 

entities outside of the planning 

coordinator area, (iv) resource planned 

outage schedules, (v) deratings and 

retirements, (vi) assumptions of 

intermittent and energy limited 

resources (such as wind and 

cogeneration), (vii) criteria for including 

planned resource additions, 

(viii) availability and delivery of fuel, 

(ix) common mode outages that affect 

resource availability, (x) environmental 

and regulatory restrictions of resources, 

(xi) available demand response 

programs, (xii) sensitivity to resource 

outage rates, (xiii) extreme weather/ 

drought condition impacts on resource 

availability, (xiv) assumptions for 

emergency operation procedures in 

order to make reserves available, and 

(xv) uncommitted resources within the 

planning coordinator area.28 Also, the 

planning coordinator must document 

that all capacity resources in the 

planning coordinator area are 

appropriately accounted for in the 

analysis.29

16. The planning coordinator is also 

required to consider the impacts of 

transmission limitations that could 

prevent the delivery of generation to the 

load including criteria for including 

planned transmission facilities in the 

study as well as transmission 

maintenance outage schedules.30

Proposed regional Reliability Standard 

BAL–502–RFC–02, Requirement R1.3.4 

requires planning coordinators to 

include in their assessment of 

transmission limits assistance from 

other interconnected systems including 

multi-area assessment considering 

transmission limitations into the study 

area. 

17. Overall, the Commission believes 

that factors to be considered in the 

resource adequacy analysis as set forth 

in Requirement R1 and, as discussed 

above, are a technically sound means to 

set up the analysis for the probability of 

not having enough resources in order to 

meet demand and avoid loss of load. 

However, the Commission questions or 

seeks clarity on three details of the 

resource adequacy analysis: (i) The loss 

of load calculation, (ii) use of capacity 

benefit margin; and (iii) meaning of 

common mode outages. 

18. Requirement R1.1 states that the 

assessment shall calculate a planning 

reserve margin that will result 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, proposed regional 

Reliability Standard BAL–502–RFC–02 

specifically identifies two 

circumstances that will not count in the 

loss of load calculation: (1) Utilization 

of direct control load management 31

and (2) curtailment of interruptible 

load.32 Notwithstanding these two 

exceptions to the loss of load 

calculation, the Commission seeks 

comment on how other actions that 

could be taken by a system operator, 

such as voltage reduction or other, nonvoluntary, types of load reduction plans, 

would be modeled and documented in 

this analysis. 

19. With respect to the capacity 

benefit margin, the Commission notes 

that the requirements do not explicitly 

state whether planning coordinators 

may rely upon capacity benefit 


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33The 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.’’ 

34See NERC Petition, Exhibit C, comments from 

ITC Transmission. 

35Reliability Standard MOD–004–1 addresses 

capacity benefit margin, 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 capacity benefit margin could be a method 

of meeting the requirements of BAL–502–RFC–02, 

the two standards do not contradict each other. 

36See NERC’s ‘‘Time Horizons’’ document, 

available on NERC’s Web site at http:// 

www.nerc.com/files/Time_Horizons.pdf. 

37NERC Petition at 22. 

38RFC Reliability Standards Development 

Procedure, at 3 (May 22, 2008) available at 

http://www.rfirst.org/Documents/Standards/

Reliability%20Standards%20Developmental

%20Procedure.pdf. 

39NERC Petition at 24. 

40Order No. 693 NOPR, FERC Stats. & Regs., 

Proposed Regulations 2004–2007, ¶ 32,608 at p. 

105. 

41RFC project SDP–501–RFC–03 was posted for 

15-day category ballot the ‘‘Draft 2 Standards 

Development Procedure’’ on Sept. 1, 2010 and can 

be found on RFC’s Web site at http://rsvp.rfirst.org/ 

SDP501RFC03/default.aspx. 

42The ‘‘Template Guide for New Standards,’’ 

‘‘Template Quality Review of Standards,’’ and ‘‘Time 

Horizons’’ documents can all be found on the NERC 

Web site at http://www.nerc.com/

commondocs.php?cd=2. 

43NERC Petition at 22. 

44 Id. 

margin 33 to satisfy BAL–502–RFC–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 MOD– 

004–1—Capacity Benefit Margin.34 The 

Commission does not believe the 

proposed regional Reliability Standard 

is in conflict with the continent-wide 

Reliability Standard, but does note there 

could be some confusion regarding 

whether capacity benefit margin could 

or could not be used in order to meet 

the Requirements of BAL–502–RFC– 

02.35 Accordingly, we seek comment on 

whether capacity benefit margin may be 

used to satisfy BAL–502–RFC–02’s 

Requirements. 

20. 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 

seeks 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 include outages of 

transmission facilities that would have 

an impact on resource or generator 

availability. 

C. Missing Time Horizons 

21. NERC’s Petition notes its concern 

that the proposed regional Reliability 

Standard BAL–502–RFC–02 does not 

identify time horizons for each 

Requirement. Time 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 the sanction associated with the 

violation is higher than it would be for 

violation of a Requirement that could be 

mitigated over a longer period of time.36

According to NERC’s template for 

Reliability Standards, each main 

Requirement in a Reliability Standard 

should be assigned one of the following 

time horizons: (1) Long-Term Planning 

(a planning horizon of one year or 

longer), (2) Operations Planning 

(operating and resource plans from dayahead 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). 

22. According to NERC, time horizons 

are used for compliance assessments as 

described in NERC’s Sanctions 

Guidelines.37 Time horizons are used 

when determining the severity of a 

violation risk factor and for determining 

the penalty for a violation. RFC states 

that it did not include time horizons 

because its Reliability Standards 

Development Procedure (RSDP) does 

not include time horizons in its 

template for Reliability Standards. The 

RFC RSDP sets forth the required 

elements of a Standard and includes a 

Reliability Standard template. RFC’s 

RSDP does not include ‘‘time horizons’’ 

as a required element.38 Thus, RFC 

states that including time horizons in 

BAL–502–RFC–02 would have been a 

deviation from its Commissionapproved Standards template. RFC also 

notes that ‘‘the standard focuses on 

‘planning oriented’ subject matter for 

one year and beyond,’’ and, as such, the 

‘‘appropriate time horizons are relatively 

straight forward.’’ 39

23. The Commission agrees with 

NERC that it is important to identify the 

time horizons for each Reliability 

Standard. However, time horizons are 

not critical to our determination of 

whether to approve this proposed 

Reliability Standard. As the 

Commission has previously stated, the 

‘‘most critical element of a Reliability 

Standard is the Requirements.’’ 40

Moreover, the Commission notes that 

with respect to proposed regional 

Reliability Standard 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. However, the Commission 

notes that RFC currently is in the 

process of modifying its RSDP such that 

it will be required to use the most 

current version of the approved NERC 

Reliability Standard template when 

developing a RFC regional Reliability 

Standard.41 NERC’s ‘‘Template Guide for 

New Standards,’’ ‘‘Template Quality 

Review of Standards,’’ and ‘‘Time 

Horizons’’ documents all call for the 

inclusion of time horizons in new 

Reliability Standards.42 Thus RFC’s 

proposed change to its RSDP would 

require RFC to tag each new Reliability 

Standard Requirement with a time 

horizon. We believe that the 

identification of the appropriate time 

horizon for each Requirement is useful 

and improves clarity and consistency in 

compliance assessments. Because RFC 

appears to be moving toward requiring 

the assignment of time horizons as part 

of its standard drafting process, as well 

as the benefits of assigning time 

horizons, the Commission proposes to 

direct RFC to add time horizons to the 

two main Requirements when RFC 

reviews regional Reliability Standard 

BAL–502–RFC–02 in its scheduled fiveyear review. 

D. Proposed Effective Date 

24. Proposed regional Reliability 

Standard BAL–502–RFC–02’s stated 

effective date is ‘‘upon RFC Board 

approval,’’ which occurred on December 

4, 2008. NERC raises the concern that 

‘‘[t]he effective date should follow the 

latest language found in the [NERC] 

standards template to meet the needs of 

the compliance program.’’ 43 NERC’s 

‘‘standards template’’ provides that the 

effective date should be ‘‘the first day of 

the first quarter after regulatory 

approval.’’ 44 RFC responded that the 

proposed RFC Board approval effective 

date set forth in BAL–502–RFC–02 is 

appropriate because of the regional 

nature of the Standard and because the 


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45Pursuant to RFC’s bylaws, RFC members are 

subject to a regional Reliability Standard once the 

Standard is approved by the RFC Board. Although 

a Board-approved Standard is enforceable under the 

RFC bylaws as a term of membership, a member 

would not be subject to potential financial 

penalties. See NERC Petition at 25. 

46 Id. 

47The Commission notes that under the current 

NERC compliance registry entities register as 

‘‘planning authorities,’’ not ‘‘planning coordinators.’’ 

NERC defines ‘‘planning coordinator’’ in its Glossary 

by simply referencing ‘‘See Planning Authority.’’ 

The Commission understands that for reliability 

purposes planning authorities and planning 

coordinators are interchangeable. Thus any entity 

registered with NERC as a planning authority is 

subject to any Reliability Standard that applies to 

planning coordinators. 

48The four planning coordinators currently 

registered in RFC are also registered as other 

functional entities. American Transmission Co., 

LLC and ITC Transmission are both registered as 

transmission owners, transmission operators and 

transmission planners. Midwest ISO is registered as 

a balancing authority, interchange authority, 

reliability coordinator and transmission service 

provider. PJM is registered as balancing authority, 

interchange authority, reliability coordinator, 

resource planner, transmission operator, 

transmission planner, and transmission service 

provider. 

49For example, it appears that the following 

continent-wide Reliability Standards allow 

planning coordinators to obtain data needed to 

conduct the resource adequacy analysis and 

assessment: (i) MOD–001, Requirement R9 (requires 

transmission service providers to provide data 

regarding available transfer capability or available 

flowgate capability calculations to the planning 

coordinator upon request); (ii) MOD–004, 

Requirement R9 (requires transmission service 

providers and transmission planners to provide 

data used for determining or allocating CBM to the 

planning coordinator upon request); (iii) MOD–008, 

Requirement R3 (requires transmission operators to 

provide the TRM implementation document to the 

planning coordinator upon request); (iv) PRC–023, 

Requirements R2 and R3 (gives planning 

coordinators access to facility ratings and the 

identification of facilities critical to reliability); and 

(v) TPL–001, TPL–002, TPL–003 and TPL–004 

(gives planning coordinators access to data related 

to the determination of whether the transmission 

system is planned to meet firm demand under 

certain conditions). 

50Western Electricity Coordinating Council 

Regional Reliability Standard Regarding Automatic 

Time Error Correction, Order No. 723, 127 FERC 

¶ 61,176, at P 39 (2009) (Final Rule). 

51Reliability Standard MOD–004–1—Capacity 

Benefit Margin, Requirements R4.1, R5.1 and R6.1 

each include a bullet stating: ‘‘Reserve margin or 

resource adequacy requirements established by 

other entities, such as municipalities, state 

commissions, regional transmission organizations, 

independent system operators, Regional Reliability 

Organizations, or regional entities.’’ (Emphasis 

added). 

52 ‘‘Generation Capability Import Requirement’’ is 

defined in the Glossary as: ‘‘The amount of 

generation capability from external sources 

identified by a Load-Serving Entity (LSE) or 

Resource Planner (RP) to meet its generation 

reliability or resource adequacy requirements as an 

alternative to internal resources.’’ 

53 ‘‘Resource Planner’’ is defined as: ‘‘The entity 

that develops a long-term (generally one year and 

beyond) plan for the resource adequacy of specific 

loads (customer demand and energy requirements) 

within a Planning Authority Area.’’ 

Requirements under BAL–502–RFC–02 

are already being implemented. 

Specifically, RFC noted that upon RFC 

Board approval, BAL–502–RFC–02 

became effective and enforceable with 

respect to RFC members under their 

‘‘Terms of Membership’’ contained in 

RFC’s bylaws.45 Because BAL–502– 

RFC–02 only applies to planning 

coordinators within RFC’s region, all of 

which are RFC members, BAL–502– 

RFC–02’s Requirements are currently 

effective. As such, no additional 

implementation time is required.46 RFC 

acknowledges that upon Commission 

approval, the Reliability Standard will 

be mandatory and enforceable, and that 

non-compliance will be subject to 

financial penalties. 

25. We propose to find that with 

respect to proposed Reliability Standard 

BAL–502–RFC–02, no additional 

implementation time is required as the 

four registered planning coordinators in 

the RFC region, as RFC members, are 

already operating under the Standard.47

There are no other planning 

coordinators to whom the requirements 

will apply after Commission approval. 

While we note that reliability standards 

are generally implemented 

prospectively, in this case the real 

impact of Commission approval is to 

make BAL–502–RFC–02 prospectively 

enforceable through civil penalties. 

Accordingly, the Commission proposes 

that Reliability Standard BAL–502– 

RFC–02 will become mandatory and 

enforceable on the effective date of the 

Commission’s final rule approving the 

Reliability Standard. 

E. Provision of Data 

26. Proposed Reliability Standard 

BAL–502–RFC–02 requires planning 

coordinators to perform a resource 

adequacy analysis and assessment. 

Gathering data is a necessary 

component of doing so. The 

Commission is concerned that proposed 

Reliability Standard BAL–502–RFC–02 

does not require other entities (loadserving 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. In short, the 

Commission is concerned that planning 

coordinators will be subject to a 

mandatory and enforceable Reliability 

Standard without the necessary tools to 

fulfill the Standard’s Requirements. The 

Commission recognizes that this 

concern is somewhat alleviated by the 

fact that, within the RFC, many of the 

planning coordinators are also the 

entities that would have the needed 

data,48 or may obtain some of the 

needed data as a result of some 

continent-wide Reliability Standards’ 

Requirements.49 The Commission 

invites 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. 

F. Regional Definitions 

27. Proposed regional Reliability 

Standard BAL–502–RFC–02 includes 

four new definitions that apply only to 

the RFC region: Resource Adequacy, Net 

Internal Demand, Peak Period, and Year 

One. NERC plans to publish the 

definitions in a distinct section of the 

NERC Glossary noting their limited 

applicability to entities within RFC. 

28. The Commission proposes to 

accept the four new defined terms to be 

applicable only in the RFC region. 

However, the Commission cautions 

NERC and the Regional Entities to be 

aware of ‘‘a potential re-proliferation of 

regional terminology, and consequently, 

the need to prevent possible 

inconsistent use of terminology among 

regions.’’ 50

29. For example, the Commission 

notes that RFC’s proposed term 

‘‘Resource Adequacy’’ is used in NERC’s 

continent-wide Reliability Standard 

MOD–004–1 51 as well as in NERC’s 

definitions of ‘‘Generation Capability 

Import Requirement’’ 52 and ‘‘Resource 

Planner’’ 53 as set forth in NERC’s 

Glossary. While RFC’s definition of 

‘‘Resource Adequacy’’ does not appear to 

conflict with the use of this term within 

the continent-wide Reliability Standard 

MOD–004–1 or in NERC’s Glossary, the 

addition of ‘‘Resource Adequacy’’ as a 

defined regional term highlights the 

need for NERC to remain vigilant 

regarding re-proliferation of regional 

terminology. This is particularly 

relevant with respect to terms like 

‘‘Resource Adequacy’’ where other 

Regional Entities may have differing 

definitions of resource adequacy and 

differing understandings of how those 

definitions apply to the continent-wide 

Reliability Standard MOD–004–1 and 

NERC’s defined terms ‘‘generation 

capability import requirement’’ and 

‘‘resource planner.’’ Accordingly, the 

Commission urges NERC and the 

Regional Entities to be vigilant to assure 

that any proposed regional definition is 

consistent with both NERC definitions 

and the approved terms used in other 

regions. 


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54NERC Petition at 24. 

55NERC Petition at Exhibit C, NERC’s April 17, 

2009 Quality Assurance Review Summary at 4. 

56Transmission Planning Reliability Standards 

TPL–001 Requirement R1, TPL–002 Requirement 

R1, TPL–003 Requirement R1, and TPL–004 

Requirement R1 all require a valid assessment 

stating: ‘‘The Planning Authority and Transmission 

Planner shall each demonstrate through a valid 

assessment. * * *’’ Further, the sub-requirements 

under Requirement R1 of each of the aboveidentified transmission planning Reliability 

Standards detail what is expected in order to have 

a valid assessment. 

57Requirement R1.3.5 of Reliability Standards 

TPL–001 through TPL–003 and Requirement 1.3.4 

of Reliability Standard TPL–004 state that in order 

to have a valid assessment, the simulation shall 

‘‘have all projected firm transfers modeled.’’ This is 

one example of how areas outside of the area being 

analyzed must be appropriately modeled in order 

to simulate the impact on the area being analyzed. 

58See Reliability Standards TPL–001–0, 

Requirements R2 and R3; TPL–002–0, Requirements 

R2 and R3; TPL–003–0, Requirements R2 and R3; 

and TPL–004–0, Requirements R2 and R3. 

59See North American Electric Reliability Corp., 

119 FERC ¶ 61,145, order on reh’g, 120 FERC 

¶ 61,145, at P 8–13 (2007) (Violation Risk Factor 

Rehearing Order). The 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 co-mingle more than one 

obligation. 

G. Technical Recommendation 

(Resources Beyond RFC Footprint) 

30. With respect to proposed BAL– 

502–RFC–02, NERC raises the concern 

of ‘‘how entities within RFC that have 

load and resources outside the RFC 

footprint account for these resources in 

their [resource adequacy] analysis.’’ 54

Specifically, NERC asked RFC to clarify 

if planning coordinators within the RFC 

footprint are expected to only include 

RFC load and resources in the analysis. 

RFC responded to NERC’s technical 

recommendation stating: 

The intent is to cover all load within the 

RFC footprint. Planning Coordinators may 

include load outside the RFC footprint as 

deemed appropriate. Even if a Planning 

Coordinator has load outside of the 

ReliabilityFirst footprint, as long as it 

operates as a single area, the adequacy of that 

Planning Coordinator area will indicate 

adequacy of the part of the area within the 

ReliabilityFirst footprint. From a converse 

perspective, if the Planning Coordinator 

operates as a single area, that area must be 

assessed as a whole or the assessment will be 

inadequate for the area within the RFC 

footprint. (If transmission constraints exist, 

the Planning Coordinator’s constrained areas 

would have to be addressed separately in any 

event.) 55

The Commission generally agrees 

with the response provided by RFC. 

However, as discussed in detail below, 

the Commission expects that a planning 

coordinator may benefit from a common 

process for including resources and 

loads outside of the RFC footprint in its 

resource adequacy analysis. 

31. As RFC noted in its response to 

NERC on this issue that in order to 

perform a valid assessment, it may be 

necessary to represent a portion of areas 

outside of the RFC footprint in order to 

determine the impact those areas may 

have on the footprint being analyzed. 

RFC has incorporated into the proposed 

regional Reliability Standard a high 

level of detail necessary to perform a 

valid assessment. Similarly, the 

Commission notes how NERC’s 

continent-wide transmission planning 

Reliability Standards 56 require a valid 

assessment, and explicitly state in the 

Standard what is expected to be 

completed in order to have a valid 

assessment. One important aspect of a 

valid assessment is that it should 

include an appropriate model of areas 

outside of the area being analyzed in 

order for the analysis to accurately 

represent what could be expected 

during actual operation.57

Otherwise, the resource adequacy 

analysis could be skewed by showing 

adequacy within the RFC footprint 

while leaving out an inadequate area 

outside of the RFC footprint. To avoid 

this potential issue, the Commission 

expects that a RFC planning coordinator 

would have a common process or 

procedure that addresses the planning 

reserves assessments, which could 

include either (i) a methodology to 

determine whether or how the planning 

coordinator would include resources 

and loads outside of the RFC footprint 

in its resource adequacy analysis or (ii) 

models which the resource adequacy 

assessment should utilize that would 

already include the appropriate 

modeling of external areas. The 

Commission seeks comments on any 

concerns or suggestions to address load 

and resources outside of the RFC 

footprint during a planning assessment 

and also seeks comments on how 

entities currently perform this task or 

other similar planning tasks where load 

and resources occur outside of 

boundaries required by the assessment. 

H. Planning Gap Identification 

32. Proposed regional Reliability 

Standard BAL–502–RFC–02 includes 

two main Requirements: (1) To annually 

perform and document resource 

adequacy analysis (R1); and (2) to 

annually document the projected load 

and resource capability for each area 

identified in the resource adequacy 

analysis (R2). BAL–502–RFC–02 does 

not include a Requirement to document 

any gap between the planning reserve 

margin calculated in R1.1 (the amount 

of planning reserve needed to ensure a 

‘‘one day in ten year’’ criterion) and the 

actual planning reserve determined in 

the resource adequacy analysis. 

33. The Commission believes that it 

would be useful for planning 

coordinators to identify and document a 

deficiency in planning reserves. 

Identification of a planning gap could 

help ensure that entities are aware of 

potential risks regarding the capability 

to balance resources and demand in a 

planning timeframe. Acknowledging 

potential risk to the Bulk-Power System 

during the planning timeframe would 

allow affected entities time to develop a 

solution before the identified deficiency 

in planning reserves leads to adverse 

reliability impacts. For example, NERC’s 

continent-wide transmission planning 

Reliability Standards 58 include 

Requirements for entities to develop a 

corrective action plan when system 

simulations indicate an inability of the 

systems to respond as prescribed in the 

Standards. Accordingly, the 

Commission proposes 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 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. This would be a 

documentation Requirement only and 

would not require entities to install 

additional generation or transmission 

capacity. 

I. Violation Risk Factors/Violation 

Security Levels 

34. To determine a base penalty 

amount for a violation of a Requirement 

within a Reliability Standard, NERC, or 

in this case RFC as the developer of 

proposed Reliability Standard BAL– 

502–RFC–02, must first determine an 

initial range for the base penalty 

amount. To do so, RFC is to assign a 

VRF to each Requirement and subRequirement 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. The Commission has 

established guidelines for evaluating the 

validity of each VRF assignment.59

35. The Reliability Standard 

developer also is to assign each 

Requirement and sub-Requirement one 

of four VSLs—low, moderate, high, and 

severe—as measurements for the degree 

to which the Requirement was violated 

in a specific circumstance. On June 19, 

2008, the Commission issued an order 


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60North American Electric Reliability Corp., 123 

FERC ¶ 61,284, at P 20–35 (Violation Severity Level 

Order), order on reh’g and compliance, 125 FERC 

¶ 61,212 (2008). The guidelines provide that VSL 

assignments should: (1) Not lower the current level 

of compliance; (2) ensure uniformity and 

consistency in the determination of penalties; (3) be 

consistent with the corresponding requirement; and 

(4) be based on a single violation. 

61We 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 that is currently pending 

with the Commission in Docket No. RR08–4–005. 

62NERC Petition at 24. 

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

March 5, 2010 Violation Severity Level Compliance 

Filing submitted in response to Order No. 722. See 

Order No. 722, 126 FERC ¶ 61,255 at P 45. 

64 5 CFR 1320.8. 

65 44 U.S.C. 3501–3520. 

66OMB’s regulations at 5 CFR 1320.3(c)(4)(i) 

require that ‘‘Any recordkeeping, reporting, or 

disclosure requirement contained in a rule of 

general applicability is deemed to involve ten or 

more persons.’’ 

establishing four guidelines for the 

development of VSLs.60

36. With respect to proposed 

Reliability Standard BAL–502–RFC–02, 

RFC assigned VRFs only to the two 

main Requirements and did not propose 

VRFs for any of the sub-Requirements.61

Requirement R1 of BAL–502–RFC–02 is 

assigned a ‘‘medium’’ VRF and 

Requirement R2 is assigned a ‘‘lower’’ 

VRF. 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 both 

VRFs and VSLs only to the main 

Requirements is consistent with NERC’s 

August 10, 2009 Informational Filing 

Regarding the Assignment of VRFs and 

VSLs.62

37. On May 5, 2010, NERC 

incorporated by reference into Docket 

No. RR08–4–005,63 its August 10, 2009 

information filing in which NERC 

proposes assigning VRFs and VSLs only 

to the main Requirements in each 

Reliability Standard, and not to the subRequirements. Because the VRFs and 

VSLs for both Requirements R1 and R2 

of proposed Reliability Standard BAL– 

502–RFC–02 are affected by the NERC’s 

pending petition, we propose to defer 

discussion on the proposed VRFs and 

VSLs assigned to BAL–502–RFC–02 

until after we act on NERC’s petition in 

Docket No. RR08–4–005. 

J. Summary 

38. In summary, proposed regional 

Reliability Standard BAL–502–RFC–02 

appears to be just, reasonable, not 

unduly discriminatory or preferential, 

and in the public interest. Accordingly, 

the Commission proposes to approve 

regional Reliability Standard BAL–502– 

RFC–02 as mandatory and enforceable 

and to accept the four related defined 

terms as terms applicable to the RFC 

region only. In addition, the 

Commission proposes to defer 

discussion on the proposed VRFs and 

VSLs, as described above. The 

Commission invites comments on these 

proposals. 

IV. Information Collection Statement 

39. The Office of Management and 

Budget (OMB) regulations require 

approval of certain information 

collection requirements imposed by 

agency rules.64 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. The Paperwork 

Reduction Act (PRA) 65 requires each 

federal agency to seek and obtain OMB 

approval before undertaking a collection 

of information directed to ten or more 

persons or contained in a rule of general 

applicability.66

40. The Commission is submitting 

these reporting and recordkeeping 

requirements to OMB for its review and 

approval under section 3507(d) of the 

PRA. Comments are solicited on the 

Commission’s need for this information, 

whether the information will have 

practical utility, the accuracy of 

provided burden estimates, ways to 

enhance the quality, utility, and clarity 

of the information to be collected, and 

any suggested methods for minimizing 

the respondent’s burden, including the 

use of automated information 

techniques. 

41. This Notice of Proposed 

Rulemaking (NOPR) proposes to 

approve one new regional Reliability 

Standard, BAL–502–RFC–02, that was 

developed by RFC, a Regional Entity, 

and submitted by NERC as the ERO. The 

proposed regional Reliability Standard 

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 

transmission-constrained sub-area 

identified in the resource adequacy 

assessment. The proposed regional 

Reliability Standard, which applies to 

approximately four planning 

coordinators located in the eastern 

portion of the U.S., does not require 

planning coordinators to file 

information with the Commission. It 

does require planning coordinators to 

develop, document, publicly post, and 

retain certain information, subject to 

compliance monitoring by RFC. 

However, the Commission does not 

believe that approval of the RFC 

regional Reliability Standard will result 

in a substantive increase in reporting 

burdens because it implements the 

current practices in RFC. As RFC has 

represented, the affected RFC-member 

planning coordinators have been subject 

to these requirements since August 2009 

and would continue to be subject to 

them even if the Commission did not 

approve BAL–502–RFC–02 as a regional 

Reliability Standard. Thus, the 

Commission finds that the requirement 

to develop, document, and maintain 

information in the regional Reliability 

Standard is a current and ongoing 

requirement for RFC members and, 

therefore, the Commission’s proposed 

action in this Notice of Proposed 

Rulemaking would not impose any 

additional burden on RFC-member 

planning coordinators. The Commission 

therefore concludes that this proposed 

rule will not substantively increase the 

reporting burden nor impose any 

additional information collection 

requirements. 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 

Commission will submit this proposed 

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. 

42. The Commission does not foresee 

any impact on the reporting burden for 

small businesses. 

43. Based on currently available 

information and the fact that the burden 

is an existing part of the business 

process for registered planning 

coordinators in the RFC region, the 

Commission estimates that the 

increased Public Reporting Burden is de 

minimis as follows: 


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67At this time, there are only four registered 

planning coordinators in the RFC region. 

68Regulations Implementing the National 

Environmental Policy Act of 1969, 52 FR 47897 

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

Preambles 1986–1990 ¶ 30,783 (1987). 

69 18 CFR 380.4(a)(2)(ii). 

70 5 U.S.C. 601–612. 

71The 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. 

72The number of copies to be filed is set forth in 

the Commission’s ‘‘Quick Reference Guide for Paper 

Submissions’’ (as updated), available at 

http://www.ferc.gov/docs-filing/efiling.asp. 

Proposed data collection FERC–725–H Number of 

respondents 

Number of 

responses 

Hours per 

respondent 

Total annual 

hours 

Registered planning coordinators 67 in the RFC region ............... 4 1 10 40 

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

InformationCollection Costs: The 

Commission seeks comments on the 

costs to comply with these 

requirements. 

• Total annual costs = $2,651.41 ((40 

hours/2080 hours/year) × $137,874/ 

year). 

• Title: (proposed) FERC–725–H, 

Regional Reliability Standard BAL–502– 

RFC–02 (Planning Resource Adequacy 

Analysis, Assessment and 

Documentation). 

• Action: Proposed 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: The 

proposed Regional Reliability Standard 

requires planning coordinators to 

document and maintain, for 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 Reliability 

Standard. 

• Internal Review: The Commission 

has reviewed the proposed regional 

Reliability Standard BAL–502–RFC–02 

and believes it to be just, reasonable, not 

unduly discriminatory or preferential, 

and in the public interest. 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. 

44. 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, Phone: (202) 502– 

8663, fax: (202) 273–0873, e-mail: 

DataClearance@ferc.gov]. Comments on 

the requirements of this order may also 

be sent to the Office of Information and 

Regulatory Affairs, Office of 

Management and Budget, Washington, 

DC 20503 [Attention: Desk Officer for 

the Federal Energy Regulatory 

Commission]. For security reasons, 

comments should be sent by e-mail to 

OMB at oira_submission@omb.eop.gov. 

Please reference FERC–725H and the 

docket number of this proposed 

rulemaking in your submission. 

V. Environmental Analysis 

45. 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.68 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.69 The 

actions proposed herein fall within this 

categorical exclusion. 

VI. Regulatory Flexibility Act 

Certification 

46. The Regulatory Flexibility Act of 

1980 (RFA) 70 generally requires a 

description and analysis of final rules 

that will have significant economic 

impact on a substantial number of small 

entities. 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.71 Moreover, 

the proposed regional Reliability 

Standards reflect a continuation of 

existing resource planning assessment 

requirements for these planning 

coordinators and are ‘‘new’’ only with 

respect to the fact that once approved by 

the Commission, they would be subject 

to enforcement by either 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. 

VII. Comment Procedures 

47. The Commission invites interested 

persons to submit comments on the 

matters and issues proposed in this 

NOPR to be adopted, including any 

related matters or alternative proposals 

that commenters may wish to discuss. 

Comments are due December 27, 2010. 

Comments must refer to Docket No. 

RM10–10–000, and must include the 

commenter’s name, the organization 

they represent, if applicable, and their 

address in their comments. 

48. The Commission encourages 

comments to be filed electronically via 

the eFiling link on the Commission’s 

Web site at http://www.ferc.gov. The 

Commission accepts most standard 

word processing formats. Documents 

created electronically using word 

processing software should be filed in 

native applications or print-to-PDF 

format and not in a scanned format. 

Commenters filing electronically do not 

need to make a paper filing. 

49. Commenters that are not able to 

file comments electronically must send 

an original copy of their comments to: 72

Federal Energy Regulatory Commission, 

Secretary of the Commission, 888 First 

Street, NE., Washington, DC 20426. 

50. All comments will be placed in 

the Commission’s public files and may 

be viewed, printed, or downloaded 

remotely as described in the Document 

Availability section below. Commenters 

on this proposal are not required to 

serve copies of their comments on other 

commenters. 

VIII. Document Availability 

51. 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. 


jlentini on DSKJ8SOYB1PROD with PROPOSALS
66046 Federal Register / Vol. 75, No. 207 / Wednesday, October 27, 2010 / Proposed Rules 

1 15 U.S.C. 3371(a)(2). 

2Section 1(c) of the Natural Gas Act (NGA) 

exempts from the Commission’s NGA jurisdiction 

those pipelines which transport gas in interstate 

commerce if (1) They receive natural gas at or 

within the boundary of a state, (2) all the gas is 

consumed within that state and (3) the pipeline is 

regulated by a state Commission. This exemption is 

referred to as the Hinshaw exemption after the 

Congressman who introduced the bill amending the 

NGA to include section 1(c). See ANR Pipeline Co. 

v. Federal Energy Regulatory Comm’n, 71 F.3d 897, 

898 (1995) (ANR) (briefly summarizing the history 

of the Hinshaw exemption). 

3Arizona Public Service Co. and Sequent Energy 

Management, L.P., 132 FERC ¶ 61,064 (2010) (APS/ 

Sequent). 

4This NOI relates to firm capacity on section 311 

and Hinshaw pipelines used for interstate service 

subject to our jurisdiction under the NGPA or NGA 

and does not extend to non-jurisdictional capacity 

used for purely intrastate service. 

5 15 U.S.C. 3371(c). 

6EPGT Texas Pipeline, 99 FERC ¶ 61,295, at 

62,252 (2002) (EPGT). 

7 18 CFR 284.121–126 (2010). 

8Certain Transportation, Sales, and Assignments 

by Pipeline Companies not Subject to Commission 

Jurisdiction Under Section 1(c) of the Natural Gas 

Act, Order No. 63, FERC Stats. & Regs. ¶ 30,118, 

at 30,824–25 (1980). 

9 18 CFR 284.7(b), 284.9(b) and 284.122 (2010). 

10Regulation of Natural Gas Pipelines After 

Partial Wellhead Decontrol, Order No. 436, FERC 

Stats. & Regs. ¶ 30,665, at 31,502 (1985). 

11See Pipeline Service Obligations and Revisions 

to Regulations Governing Self-Implementing 

Transportation and Regulation of Natural Gas 

Pipeline After Partial Wellhead Decontrol, Order 

No. 636, FERC Stats. & Regs. ¶ 30,939, order on 

reh’g, Order No. 636–A, FERC Stats. & Regs. 

¶ 30,950, order on reh’g, Order No. 636–B, 61 FERC 

¶ 61,272 (1992), order on reh’g, 62 FERC ¶ 61,007 

(1993), aff’d in part and remanded in part sub nom. 

52. 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. 

53. User assistance is available for 

eLibrary and the FERC’s Web site during 

normal business hours from FERC 

Online Support at 202–502–6652 (toll 

free at 1–866–208–3676) or e-mail at 

ferconlinesupport@ferc.gov, or the 

Public Reference Room at (202) 502– 

8371, TTY (202) 502–8659. E-mail the 

Public Reference Room at 

public.referenceroom@ferc.gov. 

By direction of the Commission. 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

[FR Doc. 2010–27132 Filed 10–26–10; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 284 

[Docket No. RM11–1–000] 

Capacity Transfers on Intrastate 

Natural Gas Pipelines 

October 21, 2010. 

AGENCY: Federal Energy Regulatory 

Commission, DOE. 

ACTION: Notice of inquiry. 

SUMMARY: The Federal Energy 

Regulatory Commission is seeking 

comments on whether and how holders 

of firm capacity on intrastate natural gas 

pipelines providing interstate 

transportation and storage services 

under section 311 of the Natural Gas 

Policy Act of 1978 and Hinshaw 

pipelines providing such services 

pursuant to blanket certificates issued 

under § 284.224 of the Commission’s 

regulations should be permitted to allow 

others to make use of their firm 

interstate capacity. 

DATES: Comments are due December 27, 

2010. 

FOR FURTHER INFORMATION CONTACT: 

James Sarikas (Technical Information), 

Office of Energy Market Regulation, 

Federal Energy Regulatory Commission, 

888 First Street, NE., Washington, DC 

20426, (202) 502–6831, 

James.Sarikas@ferc.gov; Anna 

Fernandez (Legal Information), Office of 

the General Counsel, Federal Energy 

Regulatory Commission, 888 First 

Street, NE., Washington, DC 20426, 

(202) 502–6682, 

Anna.Fernandez@ferc.gov. 

SUPPLEMENTARY INFORMATION: 

Notice of Inquiry 

1. Recently, the Commission issued 

an order finding that the Commission’s 

policy prohibiting buy/sell transactions 

applies to interstate open-access 

transportation services provided by (1) 

intrastate natural gas pipelines pursuant 

to section 311 of the Natural Gas Policy 

Act of 1978 (NGPA) 1 and (2) Hinshaw 

pipelines 2 pursuant to blanket 

certificates issued under section 284.224 

of the Commission’s regulations.3 In this 

Notice of Inquiry (NOI), the Commission 

is seeking comments on whether and 

how holders of firm interstate capacity 

on section 311 and Hinshaw pipelines 

should be permitted to allow others to 

make use of their firm interstate 

capacity, including to what extent buy/ 

sell transactions should be permitted.4

I. Current Commission Policy 

2. NGPA section 311 authorizes the 

Commission to allow intrastate natural 

gas pipelines to transport natural gas 

‘‘on behalf of’’ interstate pipelines or 

local distribution companies served by 

interstate pipelines ‘‘under such terms 

and conditions as the Commission may 

prescribe.’’ 5 NGPA section 601(a)(2) 

exempts transportation service 

authorized under NGPA section 311 

from the Commission’s NGA 

jurisdiction. Congress adopted these 

provisions in order to eliminate the 

regulatory barriers between the 

intrastate and interstate markets and to 

promote the entry of intrastate pipelines 

into the interstate market. Such entry 

eliminates the need for duplication of 

facilities between interstate and 

intrastate pipelines.6 Subpart C of the 

Commission’s Part 284 open access 

regulations (18 CFR § 2841.121–126) 

implements the provisions of NGPA 

section 311 concerning transportation 

by intrastate pipelines.7

3. Shortly after the adoption of the 

NGPA, the Commission authorized 

Hinshaw pipelines to apply for NGA 

section 7 certificates, authorizing them 

to transport natural gas in interstate 

commerce in the same manner as 

intrastate pipelines may do under NGPA 

section 311.8 Specifically, section 

284.224 of the Commission’s regulations 

provides for the issuance of blanket 

certificates to Hinshaw pipelines to 

provide open access transportation 

service ‘‘to the same extent that, and in 

the same manner’’ as intrastate pipelines 

are authorized to perform such service 

by subpart C. 

4. The Part 284, subpart C, regulations 

require that intrastate pipelines 

performing interstate service under 

NGPA section 311 must do so on an 

open-access basis.9 However, consistent 

with the NGPA’s goal of encouraging 

intrastate pipelines to provide interstate 

service, the Commission has not 

imposed on intrastate pipelines all of 

the Part 284 requirements imposed on 

interstate pipelines. For example, when 

the Commission first adopted the Part 

284 open access regulations in Order 

No. 436, the Commission exempted 

intrastate pipelines from the 

requirement that they offer open access 

service on a firm basis.10 The 

Commission found that requiring 

intrastate pipelines to offer firm service 

to out-of-state shippers could discourage 

them from providing any interstate 

service, because such a requirement 

could progressively turn the intrastate 

pipeline into an interstate pipeline 

against its will and against the will of 

the responsible state authorities. For the 

same reasons, when the Commission 

adopted Order No. 636 11 restructuring 


jlentini on DSKJ8SOYB1PROD with PROPOSALS