Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 12747 

62NAESB’s August 29, 2008 submittal is also 

available for viewing in eLibrary. The link to this 

file is as follows: http://elibrary.ferc.gov/idmws/ 

common/opennat.asp?fileID=11793503. 

excluding the last three digits of this 

document in the docket number field.62

60. User assistance is available for 

eLibrary and the FERC’s web site during 

our normal business hours. For 

assistance contact FERC Online Support 

at FERCOnlineSupport@ferc.gov or tollfree at (866) 208–3676, or for TTY, 

contact (202) 502–8659. 

List of Subjects in 18 CFR Part 38 

Conflict of interests, Electric power 

plants, Electric utilities, Incorporation 

by reference, Reporting and 

recordkeeping requirements. 

By direction of the Commission. 

Kimberly D. Bose, 

Secretary. 

In consideration of the foregoing, the 

Commission proposes to amend Chapter 

I, Title 18, part 38 of the Code of Federal 

Regulations, as follows: 

PART 38—BUSINESS PRACTICE 

STANDARDS AND COMMUNICATION 

PROTOCOLS FOR PUBLIC UTILITIES 

1. The authority citation for part 38 

continues to read as follows: 

Authority: 16 U.S.C. 791–825r, 2601–2645; 

31 U.S.C. 9701; 42 U.S.C. 7101–7352. 

2. In § 38.2, paragraphs (a)(1) through 

(11) are revised to read as follows: 

§ 38.2 Incorporation by reference of North 

American Energy Standards Board 

Wholesale Electric Quadrant standards 

(a) * * * 

(1) Open Access Same-Time 

Information Systems (OASIS), Version 

1.5 (WEQ–001, Version 002.1, March 11, 

2009) with the exception of Standards 

001–0.1, 001–0.9 through 001–0.13, 

001–1.0 through 001–1.8, and 001–9.7; 

(2) Open Access Same-Time 

Information Systems (OASIS) Standards 

& Communication Protocols, Version 1.5 

(WEQ–002, Version 002.1, March 11, 

2009); 

(3) Open Access Same-Time 

Information Systems (OASIS) Data 

Dictionary, Version 1.5 (WEQ–003, 

Version 002.1, March 11, 2009); 

(4) Coordinate Interchange (WEQ– 

004, Version 002.1, March 11, 2009); 

(5) Area Control Error (ACE) Equation 

Special Cases (WEQ–005, Version 002.1, 

March 11, 2009); 

(6) Manual Time Error Correction 

(WEQ–006, Version 002.1, March 11, 

2009); 

(7) Inadvertent Interchange Payback 

(WEQ–007, Version 002.1, March 11, 

2009); 

(8) Transmission Loading Relief— 

Eastern Interconnection (WEQ–008, 

Version 002.1, March 11, 2009); 

(9) Gas/Electric Coordination (WEQ– 

011, Version 002.1, March 11, 2009); 

(10) Public Key Infrastructure (PKI) 

(WEQ–012, Version 002.1, March 11, 

2009); and 

(11) Open Access Same-Time 

Information Systems (OASIS) 

Implementation Guide, Version 1.5 

(WEQ–013, Version 002.1, March 11, 

2009). 

* * * * * 

[FR Doc. E9–6504 Filed 3–24–09; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 40 

[Docket Nos. RM08–19–000, RM08–19–001, 

RM09–5–000, RM06–16–005] 

Mandatory Reliability Standards for the 

Calculation of Available Transfer 

Capability, Capacity Benefit Margins, 

Transmission Reliability Margins, Total 

Transfer Capability, and Existing 

Transmission Commitments and 

Mandatory Reliability Standards for the 

Bulk-Power System 

Issued March 19, 2009. 

AGENCY: Federal Energy Regulatory 

Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: Pursuant to section 215 of the 

Federal Power Act, the Commission 

proposes to approve six Modeling, Data, 

and Analysis Reliability Standards 

submitted to the Commission for 

approval by the North American Electric 

Reliability Corporation, the Electric 

Reliability Organization certified by the 

Commission. The proposed Reliability 

Standards require certain users, owners, 

and operators of the Bulk-Power System 

to develop consistent methodologies for 

the calculation of available transfer 

capability or available flowgate 

capability. 

DATES: Comments are due May 26, 2009. 

ADDRESSES: You may submit comments, 

identified by docket number by any of 

the following methods: 

• Agency Web site: http://ferc.gov. 

Documents created electronically using 

word processing software should be 

filed in native applications or print-toPDF format and not in a scanned format. 

• Mail/Hand Delivery: Commenters 

unable to file comments electronically 

must mail or hand deliver an original 

and 14 copies of their comments to: 

Federal Energy Regulatory Commission, 

Secretary of the Commission, 888 First 

Street, NE., Washington, DC 20426. 

FOR FURTHER INFORMATION CONTACT: 

Mason Emnett (Legal Information), 

Office of the General Counsel, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426, 

(202) 502–6540, Cory Lankford (Legal 

Information), Office of the General 

Counsel, Federal Energy Regulatory 

Commission, 888 First Street, NE., 

Washington, DC 20426, (202) 502–6711, 

Keith O’Neal (Technical Information), 

Office of Electric Reliability, Federal 

Energy Regulatory Commission, 888 

First Street, NE., Washington, DC 20426, 

(202) 502–6339, Christopher Young 

(Technical Information), Office of 

Electric Reliability, Federal Energy 

Regulatory Commission, 888 First 

Street, NE., Washington, DC 20426, 

(202) 502–6403. 

SUPPLEMENTARY INFORMATION: 

Table of Contents 

Paragraph 

numbers 

I. Background .......................................................................................................................................................................................... 4 

A. Order Nos. 888 and 889 ...................................................................................................................................................... 4 

B. Order Nos. 890 and 693 ...................................................................................................................................................... 8 

II. Proposed Reliability Standards ......................................................................................................................................................... 12 

A. Coordination with Business Practice Standards ............................................................................................................... 17 

B. Available Transmission System Capability, MOD–001–1 ................................................................................................ 19 

C. Capacity Benefit Margin Methodology, MOD–004–1 ........................................................................................................ 26 

D. Transmission Reliability Margin Methodology, MOD–008–1 .......................................................................................... 41 


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1 16 U.S.C. 824o. 

2North American Electric Reliability Corp., 116 

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

reh’g & compliance, 117 FERC ¶ 61,126 (ERO 

Rehearing Order) (2006), appeal docketed sub nom. 

Alcoa, Inc. v. FERC, No. 06–1426 (DC Cir. Dec. 29, 

2006). 

3Preventing Undue Discrimination and 

Preference in Transmission Service, Order No. 890, 

72 FR 12266 (Mar. 15, 2007), FERC Stats. & Regs. 

¶ 31,241 (2007), order on reh’g, Order No. 890–A, 

73 FR 2984 (Jan. 16, 2008), FERC Stats & Regs. ¶ 

31,261 (2007), order on reh’g, Order No. 890–B, 73 

FR 39092 (July 8, 2008), 123 FERC ¶ 61,299 (2008), 

order on reh’g, Order No. 890–C, 126 FERC ¶ 61,228 

(2009). 

4Reliability entities include: transmission service 

providers, planning coordinators, reliability 

coordinators, and transmission operators as those 

entities are defined in the NERC Glossary. 

Standards adopted by the North American Energy 

Standards Board (NAESB) govern disclosure of this 

information to other entities. The Commission 

addresses the proposed NAESB business practices 

in a Notice of Proposed Rulemaking issued 

concurrently in Docket No. RM05–5–013. See 

Standards for Business Practices and 

Communication Protocols for Public Utilities, 126 

FERC ¶ 61,248 (2009). 

Paragraph 

numbers 

E. Three Methodologies for Calculating Available Transfer Capability ............................................................................... 51 

1. Area Interchange Methodology, MOD–028–1 ...................................................................................................... 53 

2. Rated System Path Methodology, MOD–029–1 ................................................................................................... 61 

3. Flowgate Methodology, MOD–030–2 ................................................................................................................... 65 

F. Implementation Plan ........................................................................................................................................................... 72 

III. Discussion ......................................................................................................................................................................................... 75 

A. Implementation of the Reliability Standards .................................................................................................................... 80 

1. Available Transfer Capability Implementation Documents ................................................................................ 87 

2. Capacity Benefit Margin Implementation Documents ........................................................................................ 95 

3. Transmission Reliability Margin Implementation Documents ........................................................................... 98 

B. Proposed Modifications of the Reliability Standards ........................................................................................................ 102 

1. Availability of Implementation Documents ......................................................................................................... 103 

2. Consistent Treatment of Assumptions ................................................................................................................. 106 

3. Capacity Benefit Margin (MOD–004–1) ............................................................................................................... 109 

4. Calculation of Total Transfer Capability under the Rated System Path Methodology (MOD–029–1) ............. 112 

5. Treatment of Network Resource Designations ..................................................................................................... 116 

C. Violation Risk Factors and Violation Severity Levels ....................................................................................................... 121 

D. Disposition of Other Reliability Standards ........................................................................................................................ 130 

1. MOD–010–1 through MOD–025–1 ....................................................................................................................... 130 

2. Reliability Standards Proposed to be Retired or Withdrawn ............................................................................. 133 

E. Definitions ............................................................................................................................................................................ 139 

IV. Information Collection Statement ................................................................................................................................................... 143 

V. Environmental Analysis .................................................................................................................................................................... 148 

VI. Regulatory Flexibility Act Certification .......................................................................................................................................... 149 

VII. Comment Procedures ...................................................................................................................................................................... 151 

VIII. Document Availability ................................................................................................................................................................... 155 

1. Pursuant to section 215 of the 

Federal Power Act (FPA),1 the Federal 

Energy Regulatory Commission 

(Commission) proposes to approve, and 

direct modifications to, six Modeling, 

Data and Analysis (MOD) Reliability 

Standards submitted to the Commission 

by the North American Electric 

Reliability Corporation (NERC), which 

has been certified by the Commission as 

the Electric Reliability Organization 

(ERO) for the United States.2 The 

proposed Reliability Standards pertain 

to methodologies for the consistent and 

transparent calculation of available 

transfer capability or available flowgate 

capability. The Commission also 

proposes to retire the existing MOD 

Reliability Standards replaced by the 

versions proposed here. The retirement 

of these Reliability Standards would be 

effective upon the effective date of the 

proposed MOD Reliability Standards. 

2. In Order No. 890, the Commission 

found that the lack of a consistent and 

transparent methodology for calculating 

available transfer capability is a 

significant problem because the 

calculation of available transfer 

capability, which varies greatly 

depending on the criteria and 

assumptions used, may allow the 

transmission service provider to 

discriminate in subtle ways against its 

competitors.3 The calculation of 

available transfer capability is one of the 

most critical functions under the open 

access transmission tariff (OATT) 

because it determines whether 

transmission customers can access 

alternative power supplies. Improving 

transparency and consistency of 

available transfer capability calculation 

methodologies will eliminate 

transmission service providers’ wide 

discretion in calculating available 

transfer capability and ensure that 

customers are treated fairly in seeking 

alternative power supplies. The 

Commission believes that the Reliability 

Standards proposed here address the 

potential for undue discrimination by 

requiring industry-wide transparency 

and increased consistency regarding all 

components of the available transfer 

capability calculation methodology and 

certain definitions, data, and modeling 

assumptions. 

3. The Commission proposes to 

approve the Reliability Standards filed 

by NERC in this proceeding as just, 

reasonable, not unduly discriminatory 

or preferential, and in the public 

interest. These Reliability Standards 

represent a step forward in eliminating 

the broad discretion previously afforded 

transmission service providers in the 

calculation of available transfer 

capability. The proposed Reliability 

Standards will enhance transparency in 

the calculation of available transfer 

capability, requiring transmission 

operators and transmission service 

providers to calculate available transfer 

capability using a specific methodology 

that is both explicitly documented and 

available to reliability entities who 

request it.4 The proposed Reliability 

Standards also require documentation of 

the detailed representations of the 

various components that comprise the 

available transfer capability equation, 

including the specification of modeling 

and risk assumptions and the disclosure 

of outage processing rules to other 

reliability entities. These actions will 

make the processes to calculate 

available transfer capability and its 

various components more transparent, 


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5 16 U.S.C. 824d, 824e. 

6Promoting Wholesale Competition Through 

Open Access Non-discriminatory Transmission 

Services by Public Utilities; Recovery of Stranded 

Costs by Public Utilities and Transmitting Utilities, 

Order No. 888, 61 FR 21540 (May 10, 1996), FERC 

Stats. & Regs. ¶ 31,036 (1996), order on reh’g, Order 

No. 888–A, 62 FR 12274 (Mar. 14, 1997), FERC 

Stats. & Regs. ¶ 31,048 (1997), order on reh’g, Order 

No. 888–B, 81 FERC ¶ 61,248 (1997), order on reh’g, 

Order No. 888–C, 82 FERC ¶ 61,046 (1998), aff’d 

in relevant part sub nom. Transmission Access 

Policy Study Group v. FERC, 225 F.3d 667 (DC Cir. 

2000), aff’d sub nom. New York v. FERC, 535 U.S. 

1 (2002). 

7This is known as ‘‘functional unbundling’’ 

because the transmission element of a wholesale 

sale is separated or unbundled from the generation 

element of that sale, although the public utility may 

provide both functions. 

8See Order No. 888, FERC Stats. & Regs. ¶ 31,036 

at 31,769–70 (noting that the pro forma OATT 

expressly identified certain non-rate terms and 

conditions, such as the time deadlines for 

determining available transfer capability in section 

18.4 or scheduling changes in sections 13.8 and 

14.6, that may be modified to account for regional 

practices if such practices are reasonable, generally 

accepted in the region, and consistently adhered to 

by the transmission service provider). 

9Open Access Same-Time Information System 

(Formerly Real-Time Information Networks) and 

Standards of Conduct, Order No. 889, 61 FR 21737 

(May 10, 1996), FERC Stats. & Regs. ¶ 31,035 (1996), 

order on reh’g, Order No. 889–A, FERC Stats. & 

Regs. ¶ 31,049 (1997), order on reh’g, Order No. 

889–B, 81 FERC ¶ 61,253 (1997). 

10Order No. 889, FERC Stats. & Regs. ¶ 31,035 at 

21749. 

11 Id. at 21750. 

12 Id. 

13 Id. 

14Order No. 888, FERC Stats. & Regs. ¶ 31,036 

n.610. 

which in turn will allow the 

Commission and others to ensure 

consistency in their application. 

I. Background 

A. Order Nos. 888 and 889 

4. In April 1996, as part of its 

statutory obligation under sections 205 

and 206 of the FPA 5 to remedy undue 

discrimination, the Commission 

adopted Order No. 888 prohibiting 

public utilities from using their 

monopoly power over transmission to 

unduly discriminate against others.6 In 

that order, the Commission required all 

public utilities that own, control or 

operate facilities used for transmitting 

electric energy in interstate commerce to 

file open access non-discriminatory 

transmission tariffs that contained 

minimum terms and conditions of nondiscriminatory service. It also obligated 

such public utilities to ‘‘functionally 

unbundle’’ their generation and 

transmission services. This meant that 

public utilities had to take transmission 

service (including ancillary services) for 

their own new wholesale sales and 

purchases of electric energy under the 

open access tariffs, and to separately 

state their rates for wholesale 

generation, transmission and ancillary 

services.7 Each public utility was 

required to file the pro forma OATT 

included in Order No. 888 without any 

deviation (except a limited number of 

terms and conditions that reflect 

regional practices).8 After their OATTs 

became effective, public utilities were 

allowed to file, pursuant to section 205 

of the FPA, deviations that were 

consistent with or superior to the pro 

forma OATT’s terms and conditions. 

5. The same day it issued Order No. 

888, the Commission issued a 

companion order, Order No. 889,9

addressing the separation of vertically 

integrated utilities’ transmission and 

merchant functions, the information 

transmission service providers were 

required to make public, and the 

electronic means they were required to 

use to do so. Order No. 889 imposed 

Standards of Conduct governing the 

separation of, and communications 

between, the utility’s transmission and 

wholesale power functions, to prevent 

the utility from giving its merchant arm 

preferential access to transmission 

information. All public utilities that 

owned, controlled or operated facilities 

used in the transmission of electric 

energy in interstate commerce were 

required to create or participate in an 

Open Access Same-Time Information 

System (OASIS) that was to provide 

existing and potential transmission 

customers the same access to 

transmission information. 

6. Among the information public 

utilities were required to post on their 

OASIS was the transmission service 

provider’s calculation of available 

transfer capability. Though the 

Commission acknowledged that beforethe-fact measurement of the availability 

of transmission service is ‘‘difficult,’’ 

the Commission concluded that it was 

important to give potential transmission 

customers ‘‘an easy-to-understand 

indicator of service availability.’’ 10

Because formal methods did not then 

exist to calculate available transfer 

capability and total transfer capability, 

the Commission encouraged industry 

efforts to develop consistent methods 

for calculating available transfer 

capability and total transfer capability.11

Order No. 889 ultimately required 

transmission service providers to base 

their calculations on ‘‘current industry 

practices, standards and criteria’’ and to 

describe their methodology in an 

Attachment C to their tariffs.12 The 

Commission noted that the requirement 

that transmission service providers 

purchase only available transfer 

capability that is posted as available 

‘‘should create an adequate incentive for 

them to calculate available transfer 

capability and total transfer capability 

as accurately and as uniformly as 

possible.’’ 13

7. Although Order No. 888 obligated 

each public utility to calculate the 

amount of transfer capability on its 

system available for sale to third parties, 

the Commission did not standardize the 

methodology for calculating available 

transfer capability, nor did it impose 

any specific requirements regarding the 

disclosure of the methodologies used by 

each transmission service provider.14 As 

a result, a variety of available transfer 

capability calculation methodologies 

have been used with very few clear 

rules governing their use. Moreover, 

there was often very little transparency 

about the nature of these calculations, 

given that many transmission service 

providers historically filed only 

summary explanations of their available 

transfer capability methodologies in 

Attachment C to their OATTs. 

B. Order Nos. 890 and 693 

8. Section 215 of the FPA requires a 

Commission-certified ERO to develop 

mandatory and enforceable Reliability 

Standards, which are subject to 

Commission review and approval. If 

approved, the Reliability Standards are 

enforced by the ERO, subject to 

Commission oversight, or by the 

Commission independently. As the 

ERO, NERC worked with industry to 

develop Reliability Standards improving 

consistency and transparency of 

available transfer capability calculation 

methodologies. On April 4, 2006, as 

modified on August 28, 2006, NERC 

submitted to the Commission a petition 

seeking approval of 107 proposed 

Reliability Standards, including 23 

Reliability Standards pertaining to 

Modeling, Data and Analysis (MOD). 

The MOD group of Reliability Standards 

is intended to standardize 

methodologies and system data needed 

for traditional transmission system 

operation and expansion planning, 

reliability assessment and the 

calculation of available transfer 

capability in an open access 

environment. 

9. On February 16, 2007, the 

Commission issued Order No. 890, 

which addressed and remedied 

opportunities for undue discrimination 

under the pro forma OATT adopted in 

Order No. 888. Among other things, the 

Commission required industry-wide 

consistency and transparency of all 

components of available transfer 


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15FPA section 215(d)(5). 16 U.S.C. 824o(d)(5). 

16Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 1029. 

17 Id. P 1030. 

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

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

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

19 Id. P 1010. 

20 Id. 

21 Id. P 1029–30; see also Order No. 890, FERC 

Stats. & Regs. ¶ 31,241 at P 207. 

22Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 287–303. Some of these Reliability Standards 

required the regional reliability organizations to 

develop criteria for use by users, owners or 

operators within each region. The Commission set 

aside such Reliability Standards and directed NERC 

to provide additional details prior to considering 

them for approval. Id. P 287–303. 

23The Reliability Standards were originally due 

on December 10, 2007. See Order No. 890, FERC 

Stats. & Regs. ¶ 31,241 at P 223. NERC requested 

additional time to develop the Reliability Standards 

in order to address concerns raised in its 

stakeholder process. See NERC November 21, 2007 

Request for Extension of Time, Docket Nos. RM05– 

17–000, et al, at 7. The Commission ultimately 

granted three requests for extension of time, 

extending NERC’s deadline by over seven months, 

so that NERC could develop the Reliability 

Standards proposed here. 

24NERC designates the version number of a 

Reliability Standard as the last digit of the 

Reliability Standard number. Therefore, version 

zero Reliability Standards end with ‘‘–0’’ and 

version one Reliability Standards end with ‘‘–1.’’ 

capability calculation and certain 

definitions, data and modeling 

assumptions. The Commission 

concluded that the lack of industrywide standards for the consistent 

calculation of available transfer 

capability poses a threat to the reliable 

operation of the Bulk-Power System, 

particularly with respect to the inability 

of one transmission service provider to 

know with certainty its neighbors’ 

system conditions affecting its own 

available transfer capability values. As a 

result of this reliability concern, the 

Commission asserted that the proposed 

available transfer capability reforms 

were also supported by FPA section 

215, through which the Commission has 

the authority to direct the ERO to 

submit a Reliability Standard that 

addresses a specific matter.15 Thus, the 

Commission in Order No. 890 directed 

industry to develop Reliability 

Standards, using the ERO’s Reliability 

Standards development procedures, that 

provide for consistency and 

transparency in the methodologies used 

by transmission owners to calculate 

available transfer capability. 

10. The Commission stated in Order 

No. 890 that the available transfer 

capability-related Reliability Standards 

should, at a minimum, provide a 

framework for available transfer 

capability, total transfer capability and 

existing transmission commitments 

calculations. The Commission did not 

require a single computational process 

for calculating available transfer 

capability because, among other things, 

it found that the potential for 

discrimination and decline in reliability 

level does not lie primarily in the choice 

of an available transfer capability 

calculation methodology, but rather in 

the consistent application of its 

components, input and exchange data, 

and modeling assumptions.16 The 

Commission found that, if all of the 

available transfer capability 

components, and certain data inputs 

and assumptions are consistent, the 

three available transfer capability 

calculation methodologies would 

produce predictable and sufficiently 

accurate, consistent, equivalent and 

replicable results.17

11. On March 16, 2007, the 

Commission issued Order No. 693, 

approving 83 of the 107 Reliability 

Standards filed by NERC in April 

2006.18 Of the 83 approved Reliability 

Standards, the Commission approved 

ten MOD Reliability Standards.19

However, the Commission directed 

NERC to prospectively modify nine of 

the ten approved MOD Reliability 

Standards to be consistent with the 

requirements of Order No. 890.20 The 

Commission reiterated the requirement 

from Order No. 890 that all available 

transfer capability components (i.e., 

total transfer capability, existing 

transmission commitments, capacity 

benefit margin, and transmission 

reliability margin) and certain data 

input, data exchange, and assumptions 

be consistent and that the number of 

industry-wide available transfer 

capability calculation formulas be few 

in number, transparent and produce 

equivalent results.21 The Commission 

directed public utilities, working 

through the NERC Reliability Standards 

and NAESB business practices 

development processes, to produce 

workable solutions to implement the 

available transfer capability-related 

reforms adopted by the Commission. 

The Commission also deferred action on 

24 proposed Reliability Standards, 

which did not contain sufficient 

information to enable the Commission 

to propose a disposition.22

II. Proposed Reliability Standards 

12. In response to the requirements of 

Order No. 890 and related directives of 

Order No. 693,23 on August 29, 2008, 

NERC submitted for Commission 

approval five MOD Reliability 

Standards: MOD–001–1—Available 

Transmission System Capability, MOD– 

008–1—TRM Calculation Methodology 

(hereinafter Transmission Reliability 

Margin Methodology), MOD–028–1 

Area Interchange Methodology, MOD– 

029–1—Rated System Path 

Methodology, and MOD–030–1— 

Flowgate Methodology.24 On November 

21, 2008, NERC submitted for 

Commission approval a sixth MOD 

Reliability Standard: MOD–004–1— 

Capacity Benefit Margin (hereinafter 

Capacity Benefit Margin Methodology). 

On March 6, 2009, NERC submitted for 

Commission approval: MOD–030–2—a 

revised Flowgate Methodology 

Reliability Standard and withdrew its 

request for approval of MOD–030–1. 

13. The Available Transmission 

System Capability Reliability Standard 

(MOD–001–1) serves as an ‘‘umbrella’’ 

Reliability Standard that requires each 

applicable entity to select and 

implement one or more of the three 

available transfer capability 

methodologies found in MOD–028–1, 

MOD–029–1, or MOD–030–2. MOD– 

004–1 and MOD–008–1 provide for the 

calculation of capacity benefit margin 

and transmission reliability margin, 

which are inputs into the available 

transfer capability calculation. If 

approved, NERC states that its filing 

wholly addresses eight of the 24 

Reliability Standards that the 

Commission did not approve in Order 

No. 693 because further information was 

needed. 

14. NERC contends that the proposed 

Reliability Standards will have no 

undue negative effect on competition, 

nor will they unreasonably restrict 

available transfer capability on the BulkPower System beyond any restriction 

necessary for reliability and do not limit 

use of the Bulk-Power System in an 

unduly preferential manner. NERC 

contends that the increased rigor and 

transparency introduced in the 

development of available transfer 

capability and available flowgate 

capability calculations serve to mitigate 

the potential for undue advantages of 

one competitor over another. Under the 

proposed Reliability Standards, 

applicable entities are prohibited from 

making transmission capability 

available on a more conservative basis 

for commercial purposes than for either 

planning for native load or use in actual 

operations, thereby mitigating the 

potential for differing treatment of 

native load customers and transmission 

service customers. NERC states that data 

exchange, which has been heretofore 

voluntary, is now mandatory and it is 

required that the data be used in the 

available transfer capability/available 

flowgate capability calculations. None 

of these requirements exist in the 


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25NERC has developed a ‘‘Functional Model’’ 

that defines the set of functions that must be 

performed to ensure the reliability of the BulkPower System. The Functional Model identifies 14 

functions and the name of a corresponding entity 

responsible for fulfilling each function. NERC’s 

functional model can be found at http:// 

www.nerc.com/page.php?cid=2/247/108. 

26As noted above, the Commission addresses the 

proposed NAESB business practices in a Notice of 

Proposed Rulemaking issued concurrently in 

Docket No. RM05–5–013. 

current available transfer capabilityrelated Reliability Standards. NERC 

contends that these improvements help 

the Commission achieve many of the 

primary objectives of Order No. 890 

regarding transparency, standardization 

and consistency in available transfer 

capability calculations. 

15. NERC states that all three 

methodology Reliability Standards 

(MOD–028–1, MOD–029–1, and MOD– 

030–2) share fundamental equations 

that, while mathematically equivalent, 

are written in slightly different forms. 

As a result, the manner of determining 

the components varies between 

methodologies. The employment of any 

two methodologies, given the same 

inputs, may produce similar, but not 

identical, results. As noted by NERC 

there are fundamental differences in the 

proposed methodologies that can keep 

them from producing identical results. 

For example, the rated system path 

methodology does not use the same 

frequent simulations of power flow used 

by the other two methodologies. NERC 

states that the rated system path 

methodology therefore will rarely 

generate numbers that identically match 

those determined by an entity using the 

other two methodologies. 

16. NERC proposes to make the MOD 

Reliability Standards proposed here 

applicable to transmission operators and 

transmission service providers. NERC 

states that the drafting team considered 

applying the Reliability Standards to the 

transmission operator instead of the 

transmission service provider. 

According to NERC, the Reliability 

Standard drafting team believes that the 

NERC Functional Model supports a 

determination that responsibility for 

several of the requirements lies with the 

transmission operator.25 NERC also 

states that a number of entities argued 

in the NERC drafting process that the 

transmission service provider actually 

undertakes efforts to meet those 

requirements. NERC states that the 

drafting team believes this points to a 

delegation of tasks to a larger entity that 

is the byproduct of a regional 

transmission organization and its 

regional transmission tariff. 

Accordingly, NERC states that the MOD 

Reliability Standards retain the use of 

transmission operators in the Reliability 

Standards, and explained to entities 

how delegation or joint registration 

organizations address the compliance 

implications of the assignment. 

A. Coordination With Business Practice 

Standards 

17. NERC states that it has worked 

closely and collaboratively with 

NAESB, conducting numerous joint 

meetings and conference calls, to 

develop the Reliability Standards 

proposed here and related NAESB 

business-practice standards.26 NERC 

states that the focus of the proposed 

Reliability Standards is to address only 

the reliability aspects of available 

transfer capability and available 

flowgate capability and not to address 

the commercial aspects of available 

transfer capability, except to the extent 

that commercial system availability 

closely matches actual remaining 

system capability. The associated 

NAESB business practice standards are 

intended to focus on the competitive 

aspects of these processes. Through 

implementation of these Reliability 

Standards, access to the grid may 

indirectly be restricted, but NERC states 

that NAESB business practices and 

Commission orders related to these 

Reliability Standards ensure that any 

limitation will be applied in a manner 

that ensures open access and promotes 

competition. 

18. According to NERC, it and NAESB 

have coordinated the development of 

these business practices and the 

Reliability Standards to ensure that 

there are no duplications or double 

counting between the business practice 

standards and the Reliability Standards, 

and they will continue to coordinate as 

necessary so that the available transfer 

capability-related Reliability Standards 

are compatible and consistent. 

B. Available Transmission System 

Capability, MOD–001–1 

19. NERC proposes the Available 

Transmission System Capability 

Reliability Standard (MOD–001–1) as 

part of a set of Reliability Standards 

which are designed to work together to 

support a common reliability goal: to 

ensure that transmission service 

providers maintain awareness of 

available system capability and future 

flows on their own systems as well as 

those of their neighbors. NERC states 

that, historically, differences in 

implementation of available transfer 

capability methodologies and a lack of 

coordination between transmission 

service providers have resulted in cases 

where available transfer capability has 

been overestimated. As a result, systems 

have been oversold, resulting in 

potential or actual system operating 

limits and interconnection reliability 

operating limits being exceeded. NERC 

states that MOD–001–1 is the 

foundational Reliability Standard that 

obliges entities to select a methodology 

and then calculate available transfer 

capability or available flowgate 

capability using that methodology, 

thereby ensuring that the determination 

of available transfer capability is 

accurate and consistent across North 

America and that the transmission 

system is neither oversubscribed nor 

underutilized. 

20. NERC states that, unlike the 

current set of voluntary available 

transfer capability standards, MOD– 

001–1 requires adherence to a specific 

documented and transparent 

methodology. NERC states that it 

requires applicable entities to calculate 

available transfer capability on a 

consistent schedule and for specific 

timeframes. According to NERC, MOD– 

001–1 requires users, owners and 

operators to disclose counterflow 

assumptions and outage processing 

rules to other reliability entities. NERC 

states that this Reliability Standard 

prohibits applicable entities from 

making transmission capability 

available on a more conservative basis 

for commercial purposes than the 

system’s capability in actual operations. 

NERC’s MOD–001–1 also requires 

entities, for the first time, to exchange 

and use available transfer capability 

data. NERC states that the Reliability 

Standard reflects industry’s consensus 

best practices for determining available 

transfer capability. 

21. As proposed, this Reliability 

Standard includes nine requirements, 

which would be applicable to all 

transmission service providers and 

transmission operators. To ensure 

consistency of enforcement, NERC states 

that each requirement is supported by a 

measure that identifies what is required 

and how the requirement will be 

enforced. 

22. Under NERC’s proposed 

Requirement R1, a transmission 

operator must select one of three 

methodologies for calculating available 

transfer capability or available flowgate 

capability for each available transfer 

capability path for each time frame 

(hourly, daily or monthly) for the 

facilities in its area. As stated above, the 

three proposed methodologies are: The 

area interchange methodology, the rated 

system path methodology, and the 

flowgate methodology. 

23. Several proposed requirements 

within this Reliability Standard address 


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12752 Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 

27See Order No. 890, FERC Stats. & Regs. 

¶ 31,241 at P 237; Order No. 693, FERC Stats. & 

Regs. ¶ 31,242 at P 1051. 

28Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 1057; see also Order No. 890, FERC Stats. & Regs. 

¶ 31,241 at P 292. 

29See Order No. 890, FERC Stats. & Regs. 

¶ 31,241 at P 301; Order No. 693, FERC Stats. & 

Regs. ¶ 31,242 at P 1057. 

30These include: Each planning coordinator, 

reliability coordinator, and transmission operator 

associated with the transmission service provider’s 

area; and each planning coordinator, reliability 

coordinator, and transmission service provider 

adjacent to the transmission service provider’s area. 

31Although the Reliability Standards only require 

the transmission service provider to make the 

available transfer capability implementation 

document available to certain reliability entities, 

the NAESB standard on OASIS posting 

requirements (Standard 001–13.1.5) requires 

transmission service providers to provide a link to 

the document on OASIS. 

32See North American Electric Reliability 

Council, Glossary of Terms Used in Reliability 

Standards (Effective February 12, 2008), available 

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

Glossary_12Feb08.pdf. 

the calculation of available transfer 

capability or available flowgate 

capability. Requirement R2 requires 

each transmission service provider to 

calculate available transfer capability or 

available flowgate capability values 

hourly for the next 48 hours, daily for 

the next 31 calendar days and monthly 

for the next 12 months. Requirement R6 

requires each transmission operator in 

its calculation of total transfer capability 

or total flowgate capability to use 

assumptions no more limiting than 

those used in its planning of operations. 

NERC contends that, consistent with the 

requirements of Order No. 890 and 

related directives of Order No. 693, 

Requirement R6 will minimize the 

differences between total transfer 

capability and total flowgate capability 

for transmission and transfer capability 

used in native load and reliability 

assessment studies.27 Similarly, 

Requirement R7 requires each 

transmission service provider, in its 

calculation of available transfer 

capability or available flowgate 

capability, to use assumptions no more 

limiting than those used in its planning 

of operations. NERC contends that this 

requirement addresses the 

Commission’s directive in Order No. 

693 for the ERO to modify the available 

transfer capability Reliability Standards 

to include a requirement that the 

assumptions used in available transfer 

capability and available flowgate 

capability calculations be consistent 

with those used for planning the 

expansion or operation of the BulkPower System to the maximum extent 

possible.28 Requirement R8 requires 

each transmission service provider to 

recalculate available transfer capability 

at a certain specified interval (hourly, 

daily, monthly) unless the input values 

specified in the available transfer 

capability calculation have not changed. 

NERC contends that Requirement R8 

satisfies the Commission’s directive to 

calculate available transfer capability on 

a consistent time interval.29

24. MOD–001–1 also proposes several 

record keeping and information sharing 

requirements for transmission service 

providers. Requirement R3 requires 

each transmission service provider to 

keep an available transfer capability 

implementation document that explains 

the implementation of its chosen 

methodology(ies), its use of 

counterflows, the identities of entities 

with which it exchanges information for 

coordination purposes, any capacity 

allocation processes, and the manner in 

which it considers outages. Requirement 

R4 requires transmission service 

providers to keep specific reliability 

entities advised regarding changes to the 

available transfer capability 

implementation document.30

Requirement R5 requires the 

transmission service provider to make 

the available transfer capability 

implementation document available to 

those same reliability entities.31 Finally, 

proposed Requirement R9 allows a 

transmission service provider thirty 

calendar days to begin to respond to a 

request from any other transmission 

service provider, planning coordinator, 

reliability coordinator or transmission 

operator for certain data to be used in 

the requestor’s available transfer 

capability or available flowgate 

capability calculations. 

25. In Order No. 693, the Commission 

directed the ERO to develop 

modifications to the available transfer 

capability Reliability Standards to 

include a requirement that applicable 

entities make available assumptions and 

contingencies underlying available 

transfer capability and total transfer 

capability calculations. NERC contends 

that this Reliability Standard addresses 

this issue by requiring disclosure in the 

available transfer capability 

implementation document under 

Requirement R3.1 and part of the data 

exchange required by Requirement R9. 

NERC states that it has agreed with 

NAESB that requirements for posting 

information are more appropriately 

addressed through the NAESB process. 

Accordingly, NERC states that NAESB 

will be addressing the requirements 

associated with posting this 

information, instead of NERC. 

C. Capacity Benefit Margin 

Methodology, MOD–004–1 

26. As proposed, the Capacity Benefit 

Margin Methodology Reliability 

Standard (MOD–004–1) provides for the 

calculation of capacity benefit margin, 

which is defined by NERC as the 

amount of firm transmission capability 

preserved by the transmission service 

provider for load-serving entities, whose 

loads are located on that transmission 

service provider’s system, to enable 

access by the load-serving entities to 

generation from interconnected systems 

to meet generation reliability 

requirements.32 The purpose of this 

Reliability Standard is to promote the 

consistent and reliable calculation, 

verification, preservation, and use of 

capacity benefit margin to support 

analysis and system operations. NERC 

states that preservation of capacity 

benefit margin for a load-serving entity 

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. 

NERC states that the transmission 

transfer capability preserved as capacity 

benefit margin is intended to be used by 

the load-serving entities only in times of 

emergency generation deficiencies. 

27. NERC proposes to apply MOD– 

004–1 to transmission service providers, 

transmission planners, load-serving 

entities, resource planners and 

balancing authorities. As discussed 

more fully below, NERC states that it 

does not specify a particular 

methodology for calculating capacity 

benefit margin, but rather improves 

transparency by requiring adherence to 

specific documented and transparent 

methodology to ensure consistent and 

reliable calculation, verification, 

preservation and use of capacity benefit 

margin. 

28. To improve consistency and 

transparency in the calculation of 

capacity benefit margin, the proposed 

Reliability Standard imposes twelve 

requirements on entities electing to use 

a capacity benefit margin. Requirement 

R1 requires the transmission service 

provider that maintains capacity benefit 

margin to prepare and keep current a 

capacity benefit margin implementation 

document that includes at a minimum: 

(1) The process through which a loadserving entity within a balancing 

authority associated with the 

transmission service provider, or the 

resource planner associated with that 

balancing authority area, may ensure 

that its need for transmission capacity to 

be set aside as capacity benefit margin 

will be reviewed and accommodated by 

the transmission service provider to the 

extent transmission capacity is 


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33NERC defines the generation capability import 

requirement as the amount of generation capability 

from external sources identified by a load-serving 

entity or resource planner to meet its generation 

reliability or resource adequacy requirement as an 

alternative to internal resources. 

34Energy deficient entities are defined by NERC 

in the Capacity and Energy Emergencies Reliability 

Standard. See EOP–002–2, Attachment 1. 

35Citing Order No. 693, FERC Stats. & Regs. 

¶ 31,242 at P 1078; see also Order No. 890, FERC 

Stats. & Regs. ¶ 31,241 at P 257. 

36Citing Order No. 693, FERC Stats. & Regs. 

¶ 31,242 at P 1105. 

37Citing id. P 1077. 

available; (2) the procedure and 

assumptions for establishing capacity 

benefit margin for each available 

transfer capability path or flowgate; and 

(3) the procedure for a load-serving 

entity or balancing authority to use 

transmission capacity set aside as 

capacity benefit margin, including the 

manner in which the transmission 

service provider will manage situations 

where the requested use of capacity 

benefit margin exceeds the amount of 

capacity benefit margin available. 

29. Requirement R2 requires the 

transmission service provider to make 

its current capacity benefit margin 

implementation document available to 

the transmission operators, transmission 

service providers, reliability 

coordinators, transmission planners, 

resource planners, and planning 

coordinators that are within or adjacent 

to the transmission service provider’s 

area, and to the load-serving entities and 

balancing authorities within the 

transmission service providers area, and 

notify those entities of any changes to 

the capacity benefit margin 

implementation document prior to the 

effective date of the change. 

30. Requirements R3 and R4 require 

each load-serving entity and resource 

planner determining the need for 

transmission capacity to be set aside as 

capacity benefit margin for imports into 

a balancing authority to develop that 

need by using one or more of the 

following to determine the generation 

capability import requirement: 33 loss of 

load expectation studies, loss of load 

probability studies, deterministic riskanalysis studies, and 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. 

31. Requirement R5 requires the 

transmission service provider to 

establish at least every 13 months a 

capacity benefit margin value for each 

available transfer capability path or 

flowgate to be used for available transfer 

capability or available flowgate 

capability during the 13 full calendar 

months (months 2–14) following the 

current month (the month in which the 

transmission service provider is 

establishing the capacity benefit margin 

values). Similarly, Requirement R6 

requires the transmission planner to 

establish a capacity benefit margin value 

for each available transfer capability 

path or flowgate to be used in planning 

during each of the full calendar years 

two through ten following the current 

year (the year in which the transmission 

planner is establishing the capacity 

benefit margin values). All values must 

reflect consideration of each of the 

following, if available: (1) Any studies 

performed by load-serving entities or 

resource planners pursuant to 

Requirement R3 for loads within the 

transmission service provider’s area; or 

(2) any reserve margin or resource 

adequacy requirements for loads within 

the transmission service provider’s area 

established by other entities, such as 

municipalities, state commissions, 

regional transmission organizations, 

independent system operators, regional 

reliability organizations, or regional 

entities. Once determined, the capacity 

benefit margin values will be allocated 

along available transfer capability paths 

based on the expected import paths or 

source regions provided by load-serving 

entities or resource planners. Capacity 

Benefit Margin values for flowgates will 

be allocated based on the expected 

import paths or source regions provided 

by load-serving entities or resource 

planners and the distribution factors 

associated with those paths or regions, 

as determined by the transmission 

service provider. 

32. Requirements R7 and R8 require 

the transmission service provider and 

the transmission planner to notify, 

within 31 calendar days after the 

establishment of capacity benefit 

margin, all load-serving entities and 

resource planners that determined they 

had a need for capacity benefit margin 

of the amount, or the amount planned, 

of capacity benefit margin set aside. 

33. Requirement R9 requires the 

transmission service provider that 

maintains capacity benefit margin and 

the transmission planner to provide, 

subject to confidentiality and security 

requirements, copies of the applicable 

supporting data, including any models, 

used for determining capacity benefit 

margin or allocating capacity benefit 

margin over each available transfer 

capability path or flowgate to each of 

the associated transmission operators 

and to any transmission service 

provider, reliability coordinator, 

transmission planner, resource planner, 

or planning coordinator within 30 

calendar days of their making a request 

for the data. 

34. Requirement R10 requires the 

load-serving entity or balancing 

authority to request to import energy 

over firm transfer capability set aside as 

capacity benefit margin only when 

experiencing a declared level 2 or 

higher NERC energy emergency alert. 

35. When reviewing an arranged 

interchange using capacity benefit 

margin, Requirement R11 requires all 

balancing authorities and transmission 

service providers to waive, within the 

bounds of reliable operation, any realtime timing and ramping requirements. 

36. Requirement R12 requires all 

transmission service providers 

maintaining capacity benefit margin to 

approve, within the bounds of reliable 

operation, any arranged interchange 

using capacity benefit margin that is 

submitted by an ‘‘energy deficient 

entity’’ 34 under an energy emergency 

alert level 2 if the capacity benefit 

margin is available, the emergency is 

declared within the balancing authority 

area of the energy deficient entity, and 

the load of the energy deficient entity is 

located within the transmission service 

provider’s area. 

37. NERC states that the proposed 

Reliability Standard complies with the 

requirements of Order No. 890 and 

related directives of Order No. 693 

because it sets standards that allow 

load-serving entities to request transfer 

capability to be set aside in the form of 

capacity benefit margin in a consistent 

and transparent manner. Consistent 

with the Commission’s direction, the 

Reliability Standard provides an 

approach for determining capacity 

benefit margin that is flexible and does 

not mandate a particular 

methodology.35 NERC contends that this 

is appropriate because various parts of 

the country have already developed 

robust methodologies for determining 

capacity benefit margin. NERC states 

that Requirements R3 and R4 allow 

load-serving entities or resource 

planners to perform specific studies to 

determine their need for capacity 

benefit margin. By specifying the types 

of studies load-serving entities or 

resource planners must perform, NERC 

contends that MOD–004–1 ensures that 

capacity benefit margin and 

transmission reliability margin are not 

used for the same purpose.36 In 

response to the Commission’s 

transparency requirement,37 NERC 

states that Requirement R9 ensures that 

capacity benefit margin studies are 

made available to the appropriate 

reliability entities for their review and 


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38Citing Order No. 890, FERC Stats. & Regs. 

¶ 31,241 at P 358. NERC states that it chose thirteen 

months to ensure enough flexibility for a yearly 

update without being so prescriptive as to require 

it on a specific day. 

39Citing id. at P 257; Order No. 693, FERC Stats. 

& Regs. ¶ 31,242 at P 1082. 

40Citing Order No. 890, FERC Stats. & Regs. 

¶ 31,241 at P 256–7. 

41Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 1077. 42 Id. P 1081. 

43NERC August 29, 2008 Filing, Docket No. 

RM08–19–000 at 38 (NERC Filing). 

44This includes, but is not limited to, forced or 

unplanned outages and maintenance outages; 

allowances for parallel path (loop flow) impacts; 

allowances for simultaneous path interactions; 

variations in generation dispatch (including, but not 

limited to, forced or unplanned outages, 

maintenance outages and location of future 

generation); short-term system operator response 

(operating reserve actions); reserve sharing 

requirements; and inertial response and frequency 

bias. 

45The capacity benefit margin Reliability 

Standard, MOD–004–1, was filed on November 21, 

2008 in Docket No. RM09–5-000. 

analysis. With regard to public 

disclosure, NERC states that it has 

agreed with NAESB that requirements 

for posting information are more 

appropriately addressed through the 

NAESB process. 

38. Requirements R5 and R6 require 

that the transmission service provider 

and transmission planner utilize the 

information contained in the studies if 

it has been provided to them when 

establishing capacity benefit margin 

values and mandate the re-evaluation of 

capacity benefit margin at least once 

every thirteen months.38 NERC states 

that, consistent with Order Nos. 890 and 

693, Requirements R5 and R6 also 

require allocation of capacity benefit 

margin based on the available transfer 

methodology chosen under MOD–001– 

1.39 NERC states that Requirements R10, 

R11 and R12 specify the manner in 

which capacity benefit margin is to be 

used.40 NERC states that any additional 

requirements specified by the 

transmission service provider must be 

identified in the capacity benefit margin 

implementation document, as mandated 

in Requirement R1.3. 

39. In response to the requirement 

that capacity benefit margins be 

verifiable,41 NERC states that 

Requirements R5, R6 and R9 ensure that 

the studies used to establish a need for 

capacity benefit margin are made 

available to any of the reliability entities 

specified in Requirement R9 that 

request them. NERC explains that the 

Reliability Standard does not mandate 

the verification of requested amounts of 

capacity benefit margin because it 

would place a functional entity (either 

the transmission service provider or 

transmission planner) in the position of 

having to judge the quality of each 

request, which could create conflicts of 

interest or potentially result in liability 

for that entity. Rather than mandate any 

particular approach for validation, 

NERC states that Requirements R3 and 

R4 mandate the specific kinds of studies 

to be performed and supporting 

information that is to be maintained 

when determining the underlying need 

for capacity benefit margin. To the 

extent that entities do not use these 

methods or maintain this supporting 

information, NERC states that they will 

be in violation of the Reliability 

Standard. 

40. In response to the Commission’s 

call for clarity in the process for 

requesting capacity benefit margin,42

NERC states that Requirement R1.1 

requires the transmission service 

provider explain the process by which 

load-serving entities and resource 

planners may ensure that their need for 

transmission capacity to be set aside as 

capacity benefit margin is reviewed and 

accommodated by the transmission 

service provider to the extent 

transmission capacity is available. 

Requirement R1.3 requires the 

transmission service provider to 

describe the procedure for load-serving 

entities and resource planners to use 

transmission capacity that has been set 

aside as capacity benefit margin. If the 

requested use of capacity benefit margin 

exceeds the amount of capacity benefit 

margin available, Requirement R1.3 also 

requires a description of how the 

transmission service provider will 

manage such situations. In addition, 

NERC states that Requirements R7 and 

R8 mandate that the transmission 

service provider notify load-serving 

entities and resource planners that 

determined they had a need for capacity 

benefit margin of the amount of capacity 

benefit margin set aside, so that they 

may make informed decisions about 

how to proceed if their full request for 

capacity benefit margin could not be 

accommodated. 

D. Transmission Reliability Margin 

Methodology, MOD–008–1 

41. As proposed, the Transmission 

Reliability Margin Methodology 

Reliability Standard (MOD–008–1) 

provides for the calculation of 

transmission reliability margin, which 

describes the reliability aspects of 

determining and maintaining a 

transmission reliability margin and the 

components of uncertainty that may be 

considered when making that 

determination. The purpose of this 

Reliability Standard is to promote the 

consistent and reliable calculation, 

verification, preservation, and use of 

transmission reliability margin to 

support analysis and system operations. 

Transmission reliability margin is 

transmission transfer capability set 

aside to mitigate risks to operations, 

such as deviations in dispatch, load 

forecast, outages, and similar such 

conditions. It is distinctly different from 

capacity benefit margin, which is 

transmission transfer capability set 

aside to allow for the import of 

generation upon the occurrence of a 

generation capacity deficiency. 

42. NERC proposes to apply MOD– 

008–1 only to transmission operators 

that have elected to keep a transmission 

reliability margin. As discussed more 

fully in the discussion section below, 

NERC states that the Reliability 

Standard does not specify one approach 

for calculating transmission reliability 

margin, but rather improves 

transparency by providing the key 

requirements and items that must be 

contained in any transmission reliability 

margin methodology.43

43. To improve the transparency of 

transmission reliability margin 

calculations, the proposed Reliability 

Standard imposes five requirements on 

transmission service providers electing 

to keep a transmission reliability 

margin. Requirement R1 provides that a 

transmission operator must keep a 

transmission reliability margin 

implementation document that explains 

how specific risks such as aggregate 

load forecast uncertainty, load 

distribution uncertainty, and forecast 

uncertainty in transmission system 

topology 44 are accounted for in the 

transmission reliability margin, how 

transmission reliability margin is 

allocated, and how transmission 

reliability margin is determined for 

various time frames. 

44. Requirement R2 allows a 

transmission operator to account only 

for the risks identified in Requirement 

R1 in transmission reliability margin, 

and prohibits the transmission operator 

from incorporating risks that are 

addressed in capacity benefit margin.45

It allows reserve sharing to be included 

in transmission reliability margin. 

45. Requirement R3 requires each 

applicable entity to make the 

transmission reliability margin 

implementation document and 

associated information available to the 

following reliability entities if 

requested: Transmission service 

provider, reliability coordinator, 

planning coordinator, transmission 

planner, and transmission operator. 


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46NERC Filing at 32 (citing Order No. 890, FERC 

Stats. & Regs. ¶ 31,241 at P 273). 

47Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 1126. 

48The Commission notes that NERC uses the 

terms planning coordinator and planning authority 

interchangeably in its standards, as indicated in the 

proposed additions to the glossary of terms, 

addressed below. The interchangeable use of these 

terms may lack the clarity generally preferred, but 

the Commission understands that NERC is currently 

working on modifications to address this issue. 

49See Order No. 890, FERC Stats. & Regs. ¶ 

31,241 at P 273. 

50 Id. P 210. 

51A fill-in-the-blank Reliability Standard requires 

the regional entities to develop criteria for use by 

users, owners or operators within each region. In 

Order No. 693, the Commission held 24 Reliability 

Standards (mainly fill-in-the-blank standards) as 

pending until further information was provided on 

each standard and requires users, owners and 

operators to follow these pending standards as 

‘‘good utility practice’’ pending their approval by 

the Commission. 

46. Requirement R4 provides that 

each applicable transmission operator 

must determine the transmission 

reliability margin value per the methods 

described in the transmission reliability 

margin implementation document at 

least once every thirteen months. 

Finally, Requirement R5 states that each 

applicable transmission operator must 

provide that transmission reliability 

margin value to its transmission service 

providers and transmission planners no 

more than seven days after it has been 

determined. 

47. NERC states that MOD–008–1 

complies with Order No. 890 by 

specifying the critical areas of analysis 

required for transmission reliability 

margin.46 Further, it states that it has 

specified the appropriate uses of 

transmission reliability margin in 

Requirement R1 and prohibited the use 

of other values and double counting in 

Requirement R1. In addition, it 

maintains that MOD–008–1 complies 

with Order No. 693 by imposing clear 

requirements for making documents 

supporting the transmission reliability 

margin determination available through 

Requirements R1 and R3. 

48. In response to the requirement to 

expand the applicability of the 

transmission reliability margin 

Reliability Standard to planning 

authorities and reliability 

coordinators,47 NERC states that the 

drafting team was not able to identify 

any requirements for these entities, 

based on the current drafting of the 

Reliability Standard. Therefore, these 

entities are not included in the 

proposed Reliability Standard. NERC 

states that, until such time as the 

transmission reliability margin 

methodology becomes more detailed, 

there does not seem to be any 

measurable action that can be imposed 

on the planning coordinator 48 or 

reliability coordinator. 

49. In response to the Commission’s 

statement that it would not require 

transfer capability that is set aside as 

transmission reliability margin to be 

sold on a non-firm basis,49 NERC states 

that it has included this requirement in 

each of the three methodologies as a 

part of firm and non-firm equations. 

NERC states that, because some of the 

uncertainties included in the 

transmission reliability margin may 

reduce or be eliminated as one 

approaches real time, the non-firm 

equations allow for the partial release of 

transmission reliability margin. In the 

Area Interchange Methodology (MOD– 

028–1), this is addressed in 

Requirement R11; in the Rated System 

Path Methodology (MOD–029–1), this is 

addressed in Requirement R8; and in 

the Flowgate Methodology (MOD–030– 

2), this is addressed in Requirement R9. 

50. NERC contends that choosing a 

‘‘best’’ approach to transmission 

reliability margin calculation would 

require a much more thorough technical 

effort. NERC therefore requests that the 

Commission provide additional 

guidance on this topic regarding its 

priority and a determination whether or 

not such an effort should be included in 

NERC’s annual planning process. 

E. Three Methodologies for Calculating 

Available Transfer Capability 

51. In Order No. 890, the Commission 

did not require a uniform methodology 

for calculating available transfer 

capability. The Commission noted that 

NERC was developing Reliability 

Standards for three available transfer 

capability calculation methodologies 

and concluded that, if all of the 

available transfer capability components 

and certain data inputs and assumptions 

are consistent, the three available 

transfer capability calculation 

methodologies being developed by 

NERC will produce predictable and 

sufficiently accurate, consistent, 

equivalent and replicable results.50

Consistent with Order No. 890, NERC 

proposes three methodologies for 

calculating available transfer capability 

as detailed in the following Reliability 

Standards: MOD–028–1, MOD–029–1 

and MOD–030–2. NERC contends that 

these three methodologies meet the 

requirements established by the 

Commission in Order No. 890, as well 

as those established in Order No. 693. 

52. NERC asserts that the three 

methodologies are a significant 

improvement over the existing available 

transfer capability related requirements. 

While current MOD–001–0 is essentially 

a ‘‘fill-in-the-blank’’ Reliability 

Standard,51 the proposed methodologies 

replace the original fill-in-the-blank 

standard by specifying in detail how 

total transfer capability is to be 

determined—from modeling 

requirements, to the simulation of 

dispatch to determine native load 

impacts, to the treatment of reservations 

and to the incorporation of neighboring 

data. According to NERC, MOD–001–1 

specifies how existing transmission 

commitments and available transfer 

capability are to be determined in detail 

and clearly describes the treatment of 

capacity benefit margin and 

transmission reliability margin in the 

available transfer capability equations. 

Thus, NERC contends, these Reliability 

Standards reduce the potential for 

seams discrepancies and improve the 

wide-area understanding of the BulkPower System on a forward-looking 

basis. NERC states that, by promoting 

consistency, standardization and 

transparency, they directly support and 

improve the reliability of the BulkPower System and help achieve the 

Commission’s objectives stated in Order 

No. 890. 

1. Area Interchange Methodology, 

MOD–028–1 

53. NERC states that the area 

interchange methodology is 

characterized by determination of 

incremental transfer capability via 

simulation, from which total transfer 

capability can be mathematically 

derived. Capacity benefit margin, 

transmission reliability margin, and 

existing transmission commitments are 

subtracted from the total transfer 

capability, and postbacks and 

counterflows are added, to derive 

available transfer capability. NERC also 

states that, under the area interchange 

methodology, total transfer capability 

results are generally reported on an area 

to area basis. 

54. MOD–028–1 describes the area 

interchange methodology (previously 

referred to as the network response 

available transfer capability 

methodology) for determining available 

transfer capability. NERC intends to use 

the Area Interchange Methodology 

Reliability Standard to increase 

consistency and reliability in the 

development and documentation of 

transfer capability calculation for shortterm use performed by entities using the 

area interchange methodology to 

support analysis and system operations. 

55. This Reliability Standard would 

apply only to transmission operators 

and transmission service providers that 


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52This information includes: Expected generation 

and transmission outages, additions, and 

retirements; load forecasts; and unit commitment 

and dispatch order. 

have elected to implement this 

particular methodology as part of their 

compliance with MOD–001–1, 

Requirement R1. The proposed 

Reliability Standard consists of eleven 

requirements. Requirement R1 provides 

the additional information that a 

transmission service provider using the 

area interchange methodology must 

include in its available transfer 

capability implementation document. 

This includes information describing 

how the selected methodology has been 

implemented, in such detail that, given 

the same information used by the 

transmission operator, the results of the 

total transfer capability calculations can 

be validated; a description of the 

manner in which the transmission 

operator will account for interchange 

schedules in the calculation of total 

transfer capability; any contractual 

obligations for allocation of total 

transfer capability; a description of the 

manner in which contingencies are 

identified for use in the total transfer 

capability process; and information on 

how sources and sinks for transmission 

service are accounted for in available 

transfer capability calculations. 

56. Pursuant to Requirement R2, each 

transmission operator must calculate 

total transfer capability using a model 

that meets the scope specified in the 

requirement and includes rating 

information specified by generator 

owners and transmission owners whose 

equipment is represented in the model. 

57. Requirement R3 details the 

information the transmission operator 

must include in its determination of 

total transfer capability for the on-peak 

and off-peak intra-day and next day 

time periods, as well as days two 

through 31 and for months two through 

13.52 Requirement R4 requires each 

transmission operator to determine total 

transfer capability while modeling 

contingencies and reservations 

consistently, and respect any 

contractual allocations of total transfer 

capability. 

58. Requirement R5 provides that 

each transmission operator must 

determine total transfer capability on a 

periodic basis (as specified in the 

requirement) or upon certain operating 

conditions significantly affecting bulk 

electric system topology. 

59. Requirement R6 provides the 

detailed process by which each 

transmission operator must establish 

total transfer capability, which must be 

provided to the transmission service 

provider within the time frames 

specified in Requirement R7. 

60. Requirements R8 through R11 

specify the formulas and detailed 

specifications of the variables for 

calculating firm and non-firm existing 

transmission commitments and firm and 

non-firm available transfer capability. 

2. Rated System Path Methodology, 

MOD–029–1 

61. NERC states that the rated system 

path methodology is characterized by an 

initial total transfer capability, 

determined via simulation. As with the 

area interchange methodology, capacity 

benefit margin, transmission reliability 

margin, and existing transmission 

commitments are subtracted from the 

total transfer capability, and postbacks 

and counterflows are added, to derive 

available transfer capability. NERC also 

states that, under the rated system path 

methodology, total transfer capability 

results are generally reported as specific 

transmission path capabilities. 

62. MOD–029–1 describes the rated 

system path methodology for 

determining available transfer 

capability. NERC intends to use this 

Reliability Standard to increase 

consistency and reliability in the 

development and documentation of 

transfer capability calculations for shortterm use performed by entities using the 

rated system path methodology to 

support analysis and system operations. 

63. This Reliability Standard would 

apply only to transmission operators 

and transmission service providers that 

have elected to implement rated system 

path methodology as part of their 

compliance with MOD–001–1 

Requirement R1. To implement this 

calculation, this Reliability Standard 

consists of eight requirements. Under 

Requirement R1, a transmission 

operator must calculate total transfer 

capability using a model that meets the 

scope and criteria specified in the 

requirement. Requirement R2 lists a 

detailed process by which the 

transmission operator must establish 

total transfer capability. Pursuant to 

Requirement R3, the transmission 

operator must establish total transfer 

capability as the lesser of the system 

operating limit or the value determined 

in Requirement R2. The transmission 

operator must then provide a 

transmission service provider with the 

appropriate total transfer capability 

values and study report within seven 

days of finalization of the study report 

required in Requirement R4. 

64. Requirements R5 through R8 

provide that each applicable 

transmission service provider must 

calculate firm and non-firm existing 

transmission commitments and firm and 

non-firm available transfer capability 

using a specified formula and detailed 

specification of the variables. 

3. Flowgate Methodology, MOD–030–2 

65. NERC states that the flowgate 

methodology is characterized by 

identification of key facilities as 

flowgates. Total flowgate capabilities are 

determined based on facility ratings and 

voltage and stability limits. The impacts 

of existing transmission commitments 

are determined by simulation. To 

determine the available flowgate 

commitments, the transmission service 

provider or operator must subtract the 

impacts of existing transmission 

commitments, capacity benefit margin, 

and transmission reliability margin, and 

add the impacts of postbacks and 

counterflows. Available flowgate 

capability can be used to determine 

available transfer capability. 

66. MOD–030–2 describes the 

flowgate methodology (previously 

referred to as the flowgate network 

response available transfer capability 

methodology) for determining available 

transfer capability. NERC states that the 

purpose of the Flowgate Methodology 

Reliability Standard is to increase 

consistency and reliability in the 

development and documentation of 

transfer capability calculations for shortterm use performed by entities using the 

flowgate methodology to support 

analysis and system operations. 

67. This Reliability Standard would 

apply only to transmission operators 

and transmission service providers that 

have elected to implement this 

particular methodology as part of their 

compliance with MOD–001–2. As 

proposed, the Flowgate Methodology 

consists of eleven requirements. 

Requirement R1 states that a 

transmission service provider 

implementing this methodology must 

include the following information in its 

available transfer capability 

implementation document in addition 

to that already required in the Available 

Transmission System Capability 

Reliability Standard (MOD–001–1): the 

criteria used by the transmission 

operator to identify sets of transmission 

facilities as flowgates that are to be 

considered in available flowgate 

capability calculations, and information 

on how sources and sinks for 

transmission service are accounted for 

in available flowgate capability 

calculations. 

68. Under Requirement R2, each 

applicable transmission operator must 

determine and manage the flowgates 

used in the methodology based on the 

criteria listed in the requirement, 


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53MOD–030–2 is identical to MOD–030–1 except 

for certain modifications to Requirements R2 and 

R11. First, NERC added new sub-requirements 

R2.1.1.3 and R2.1.2.3. to clarify that, if any limiting 

element is kept within its limit for its associated 

worst contingency by operating within the limits of 

another flowgate, then no new flowgate needs to be 

established for such limiting elements or 

contingencies. Second, NERC modified subrequirement R2.1.3. to state that the list of flowgates 

does not need to include any flowgates created to 

address temporary operating conditions. Finally, 

NERC modified Requirement R11 to eliminate the 

obligation to convert total flowgate capability to 

total transfer capability. The Commission notes that 

the modification to Requirement R11 does not alter 

the posting requirements of 18 CFR 37.6(b)(3). 

54Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 313. 

55Requirement R11 of MOD–030–1 would have 

directed transmission service providers to use the 

same formula to convert total flowgate capability to 

total transfer capability. The formula provided in 

Requirement R11 of MOD–030–2 eliminates this 

obligation. As noted above, this modification does 

not alter the posting requirements of 18 CFR 

37.6(b)(3). 

56Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 68. 

establish its total flowgate capability 

based on the criteria listed in the 

requirement, and provide total flowgate 

capability to the transmission service 

provider within seven days of their 

determination.53 To achieve consistency 

in each component of the available 

transfer capability calculation, the 

Commission, in Order No. 890, directed 

public utilities, working through NERC, 

to develop an available flowgate 

capability definition and requirements 

used to identify a particular set of 

transmission facilities in a flowgate.54

As part of the development of the 

Flowgate Methodology, NERC states that 

the Reliability Standard drafting team 

developed a definition of available 

flowgate capability. In addition, NERC 

states that Requirement R2 of this 

Reliability Standard contains a list of 

minimum characteristics that are to be 

used to identify a particular set of 

transmission facilities as a flowgate. 

69. Requirement R3 requires the 

transmission operator to provide the 

transmission service provider with a 

transmission model that meets a 

specified criteria and Requirement R4 

provides that the transmission service 

provider must evaluate reservations 

consistently when determining available 

flowgate capability. When determining 

available flowgate capability, 

Requirement R5 provides that each 

transmission service provider must use 

the models given to it as described in 

Requirement R3, include appropriate 

outages, and use the available flowgate 

capability on external flowgates as 

provided by the transmission service 

provider calculating available flowgate 

capability for those flowgates. 

70. Requirements R6 and R7 require 

each transmission service provider to 

calculate the impact of firm and nonfirm existing transmission commitments 

using a specified process. The 

transmission service provider must 

calculate firm and non-firm available 

flowgate capability using the formula 

and detailed specification of the 

variables found in Requirements R8 and 

R9. 

71. Under Requirement R10, each 

transmission service provider shall 

recalculate available flowgate capability 

at a certain specified interval (hourly 

once per hour, daily once per day, 

monthly once per week) unless the 

input values specified in the available 

flowgate capability calculation have not 

changed. NERC contends that this 

requirement satisfies the requirement in 

Order No. 890 and Order No. 693 that 

transmission service providers 

recalculate available transfer capability 

on a consistent time interval. Finally, 

Requirement R11 provides the formula 

and variables that a transmission service 

provider must use if it desires to convert 

available flowgate capability to available 

transfer capability.55

F. Implementation Plan 

72. NERC proposes that the Available 

Transmission System Capability 

Reliability Standard and the three 

methodology Reliability Standards 

become effective the first day of the first 

quarter no sooner than one calendar 

year after approval of all of these four 

Reliability Standards by all appropriate 

regulatory authorities where approval is 

required or is otherwise effective in 

those jurisdictions where approval is 

not explicitly required. According to 

NERC, since the three methodology 

Reliability Standards require 

information from neighboring reliability 

entities for use in the development of its 

available transfer capability and 

available flowgate capability values that 

is compulsory under Requirement R9 of 

the Available Transmission System 

Capability Reliability Standard (MOD– 

001–1), none of the methodology 

Reliability Standards can be effectively 

implemented unless and until that 

Reliability Standard has been 

implemented by all entities in all 

jurisdictions. 

73. NERC states that, although some 

entities may already be implementing 

the requirements in the Reliability 

Standards, many others are not, 

especially with regard to the data 

exchange requirements listed in 

Requirement R9 of MOD–001–1. 

Accordingly, software changes, 

associated testing, and possible tariff 

filings will be required to comply with 

the proposed Reliability Standards. 

Therefore, NERC maintains that a 

minimum of one year from regulatory 

approval should be allowed for entities 

to comply. 

74. NERC proposes that each of the 

Capacity Benefit Margin (MOD–004–1) 

and Transmission Reliability Margin 

(MOD–008–1) Reliability Standards 

require compliance on the first day of 

the first quarter no sooner than one 

calendar year after approval of the 

Reliability Standard by appropriate 

regulatory authorities where approval is 

required or, where approval is not 

explicitly required, when the Reliability 

Standard is otherwise effective. 

According to NERC, unlike the other 

four proposed Reliability Standards 

included in this filing, the Transmission 

Reliability Margin Reliability Standard 

replaces the existing Reliability 

Standard MOD–008–0 and the Capacity 

Benefit Margin Reliability Standard 

replaces MOD–004–0. As such, they do 

not require coordinated 

implementation, as entities may rely on 

the previous version of the Reliability 

Standards if any delay in implementing 

the Reliability Standards occurs. NERC 

states that, although many entities 

already use transmission reliability 

margin and capacity benefit margin, 

compliance with these Reliability 

Standards may require software 

changes, software regression testing, and 

possible tariff changes. To accommodate 

these needs, NERC believes a one-year 

implementation period is appropriate. 

III. Discussion 

75. The Commission proposes to 

approve the revised MOD Reliability 

Standards and related additions to the 

glossary of terms, to be effective as 

proposed by NERC, as just, reasonable, 

not unduly discriminatory or 

preferential, and in the public interest. 

These Reliability Standards represent a 

step forward in eliminating the broad 

discretion previously afforded 

transmission service providers in the 

calculation of available transfer 

capability. As the Commission 

explained in Order No. 890, excessive 

discretion in the calculation of available 

transfer capability gives transmission 

service providers the opportunity to 

discriminate in subtle ways in the 

provision of open access transmission 

service.56 On systems where 

transmission capacity is constrained, a 

lack of transparency and consistency in 

the calculation of available transfer 

capability has led to recurring disputes 

over whether transmission service 

providers have performed those 


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57MOD–001–1, Requirements R6 and R7. 

58MOD–001–1, Requirement R3. 

59Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 

at P 51. 

calculations in a way that discriminates 

against competitors. 

76. The Commission acted in Order 

No. 890 to limit this remaining 

opportunity for discrimination by 

directing public utilities, working 

through NERC, to develop Reliability 

Standards to govern the consistent and 

transparent calculation of available 

transfer capability by transmission 

service providers. In Order No. 693, the 

Commission implemented that directive 

by requiring NERC to prospectively 

modify the MOD Reliability Standards it 

filed in April 2006 to address the 

requirements of Order No. 890. The 

proposed Reliability Standards satisfy 

these requirements by enhancing 

transparency and consistency in the 

calculation of available transfer 

capability, mandating that transmission 

service providers and transmission 

operators perform their calculations in 

accordance with methodologies that are 

both explicitly documented and 

available to reliability entities who 

request them. The proposed Reliability 

Standards also require documentation of 

the detailed representations of the 

various components that comprise the 

available transfer capability equation, 

and require transmission service 

providers and transmission operators to 

specify modeling and risk assumptions 

and disclosure of outage processing 

rules to other reliability entities. These 

actions will make the processes to 

calculate available transfer capability 

and its various components more 

transparent which, in turn, will allow 

the Commission and others to ensure 

that those calculations are performed 

consistently. 

77. Although the Commission 

believes that the proposed Reliability 

Standards generally comply with the 

requirements of Order No. 890 and 

related directives of Order No. 693, the 

Commission is concerned that the 

implementation documents used by 

each transmission service provider to 

implement the Reliability Standards 

could provide continuing opportunities 

to discriminate in the provision of 

transmission service. As discussed in 

further detail below, the Commission 

proposes to direct the ERO to perform 

an audit of the implementation 

documents to determine if they provide 

sufficient transparency to enable the 

Commission and others to replicate and 

verify each transmission service 

provider’s calculations. Without 

adequate transparency, it will be 

impossible for the Commission to 

ensure that transmission service 

providers are consistently performing 

their available transfer capability 

calculations when responding to 

requests for transmission service. 

Ensuring adequate transparency also 

will enable the Commission and others 

to verify that data and modeling 

assumptions used to calculate available 

transfer capability are being used 

consistently during relevant timeframes, 

such as in the calculation of short-term 

available transfer capability and the 

planning of operations, as required by 

the proposed Reliability Standards.57

78. The Commission also has concern 

regarding several of the substantive 

requirements of the proposed Reliability 

Standards. To address these concerns, 

the Commission proposes to direct the 

ERO to develop modifications to the 

Reliability Standards to address the 

discrete issues involving: the 

availability of each transmission service 

provider’s implementation documents; 

the consistent treatment of assumptions 

in the calculation of available transfer 

capability; the calculation, allocation, 

and use of capacity benefit margin; the 

calculation of total transfer capability 

under the Rated System Path 

Methodology; and, the treatment of 

network resource designations in the 

calculation of available transfer 

capability. 

79. Finally, we note that the 

Commission in this proceeding 

addresses only those revisions to the 

Reliability Standards filed to comply 

with the available transfer capabilityrelated requirements of Order No. 890, 

as implemented by Order No. 693. In 

Order No. 693, the Commission also 

directed the ERO to develop 

modifications to a number of other 

Reliability Standards. The Commission 

expects the ERO to comply in a timely 

and complete manner with those 

directives, to the extent it has not 

already done so. 

A. Implementation of the Reliability 

Standards 

80. The Available Transmission 

System Capability Reliability Standard 

(MOD–001–1) serves as an ‘‘umbrella’’ 

Reliability Standard that requires each 

applicable entity to select and 

implement one or more of the three 

available transfer capability 

methodologies found in MOD–028–1, 

MOD–029–1, or MOD–030–2. MOD– 

004–1 and MOD–008–1 provide for the 

calculation of capacity benefit margin 

and transmission reliability margin, 

which are inputs into the available 

transfer capability calculation. Together, 

these Reliability Standards require 

transmission service providers and 

transmission operators to prepare and 

keep current implementation 

documents that contain certain 

information specified in the Reliability 

Standards. The available transfer 

capability implementation documents 

must describe the available transfer 

capability methodology in such detail 

that the results of their calculations can 

be validated when given the same 

information used by the transmission 

service provider or transmission 

operator.58

81. The Commission is concerned that 

the proposed Reliability Standards 

could be implemented by a particular 

transmission service provider or 

transmission operator in a way that 

enables them to retain the ability to 

unduly discriminate in the provision of 

open access transmission service. 

Although the Reliability Standards 

require transmission service providers 

to include certain minimum information 

in each of the implementation 

documents, transmission service 

providers are also permitted to include 

additional, undefined parameters and 

assumptions in those documents. This 

could include criteria that are 

themselves not sufficiently transparent 

to allow the Commission and others to 

determine whether they have been 

consistently applied by the transmission 

service provider in particular 

circumstances. This discretion appears 

in the three available transfer capability 

methodologies (MOD–028–1, MOD029– 

1, and MOD–030–2), as well as the 

Reliability Standards governing the 

calculation of capacity benefit margin 

(MOD–004–1) and transmission 

reliability margin (MOD–008–1). 

82. It is appropriate for transmission 

service providers to retain some level of 

discretion in the calculation of available 

transfer capability. Requiring absolute 

uniformity in criteria and assumptions 

across all transmission service providers 

would preclude transmission service 

providers from calculating available 

transfer capability in a way that 

accommodates the operation of their 

particular systems. The Reliability 

Standards need not be so specific that 

they address every unique system 

difference or differences in risk 

assumptions when modeling expected 

flows. Each transmission service 

provider should retain some discretion 

to reflect unique system conditions or 

modeling assumptions in its available 

transmission capability methodology.59

Any such system conditions or 

modeling assumptions, however, must 

be made sufficiently transparent and be 


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60The audit should be prepared and submitted by 

NERC staff (or any consultants it may choose to 

employ), rather than the drafting teams that 

developed the proposed Reliability Standards. 

61Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 208. 62 Id. P 210. 

63MOD–028–1, Requirement R3.1. 

64MOD–029–1, Requirement R1.1.9. 

65MOD–029–1, Requirement R1.1.10. 

implemented consistently for all 

transmission customers. 

83. In order to ensure that this occurs, 

the Commission proposes to direct the 

ERO to conduct an audit of the various 

implementation documents developed 

by transmission service providers to 

confirm that the complete available 

transfer capability methodologies 

reflected therein, including the 

calculation of each component of 

available transfer capability, are 

sufficiently transparent to allow the 

Commission and others to replicate and 

verify those calculations and thereby 

ensure that they are being implemented 

consistently for all transmission 

customers. This audit would review the 

additional parameters and assumptions 

included by transmission service 

providers in their implementation 

documents as of the date the Reliability 

Standards become effective, analyzing 

all parameters and assumptions to 

determine if they are detailed enough to 

enable replication and verification of 

calculations. Upon review of this 

analysis, the Commission may direct the 

ERO to develop a modification to one or 

more of the Reliability Standards to 

address any lack of transparency that 

may exist in the calculation of available 

transfer capability and each of its 

components. 

84. The Commission proposes to 

direct the ERO to complete this audit no 

later than 180 days after the effective 

date of the Reliability Standards, as 

approved by a final rule in this docket.60

The Commission also proposes to direct 

NERC to submit a timeline for the 

completion of this audit within 30 days 

of the issuance of the final rule in this 

docket. The Commission discusses 

below the specific issues to be analyzed 

by NERC in its audit. 

85. Before turning to those issues, the 

Commission reiterates that our intent is 

not to require the development of a 

single, uniform methodology for 

calculating available transfer capability 

or its components. In Order No. 890, the 

Commission found that the potential for 

discrimination does not lie primarily in 

the choice of an available transfer 

capability calculation methodology, but 

rather in the consistent application of its 

components.61 The Commission 

acknowledged that NERC was 

developing standards for three available 

transfer capability calculation 

methodologies. The Commission 

concluded that, if all of the available 

transfer capability components and 

certain data inputs and assumptions are 

consistent, the three available transfer 

capability calculation methodologies 

being developed by NERC would 

produce predictable and sufficiently 

accurate, consistent, equivalent and 

replicable results.62

86. As the Commission explains in 

Order No. 890–C, issued concurrently 

with this order, this does not mean that 

the results of available transfer 

capability calculations on either side of 

an interface must be identical in every 

instance. There are fundamental 

differences in the three available 

transfer capability methodologies set 

forth in the proposed Reliability 

Standards that may keep them from 

producing identical results. Even where 

the same methodology is used by 

transmission service providers on either 

side of an interface, unique system 

differences or differences in risk 

assumptions can lead to variations in 

available transfer capability values. The 

central goal of the available transfer 

capability reforms adopted in Order No. 

890 was to limit remaining 

opportunities for discrimination by 

requiring each transmission service 

provider’s available capability transfer 

methodology to be sufficiently 

transparent to allow for independent 

validation that it has been consistently 

applied. Subject to confirmation by 

NERC through its audit, the Commission 

believes that the Reliability Standards 

will provide the necessary level of 

transparency and, therefore, the results 

of available transfer capability 

calculations will be sufficiently 

accurate, consistent, equivalent and 

replicable. 

1. Available Transfer Capability 

Implementation Documents 

87. First, the Commission proposes to 

direct the ERO to study whether each 

available transfer capability 

implementation document developed by 

each transmission service provider 

under the Reliability Standards contains 

a level of specificity sufficient to allow 

the Commission and others to replicate 

and verify calculations of available 

transfer capability and available 

flowgate capability. Although MOD– 

028–1, MOD–029–1, and MOD–030–2 

each improves transparency and 

consistency by requiring transmission 

service providers to use certain 

specified data and variables in their 

calculations, they also allow 

transmission service providers to use 

additional parameters and assumptions 

as long as they are specified in their 

implementation documents. Other than 

their inclusion in the available transfer 

capability implementation document, 

there do not appear to be any 

appreciable factors limiting a 

transmission service provider’s 

discretion to use particular parameters 

and assumptions. 

88. For example, in the Area 

Interchange Methodology (MOD–028– 

1), Requirement R3.1 establishes 

variables to be used when calculating 

on-peak and off-peak intra-day and 

next-day total transfer capabilities. The 

requirement also allows transmission 

operators to use ‘‘any other values and 

additional parameters as specified in the 

[available transfer capability 

implementation document].’’63 The 

requirement does not provide any 

further limitation on the other values 

and additional parameters. Thus, 

although the requirement promotes 

transparency and consistency, it could 

allow an entity to adopt values and 

parameters that are not sufficiently 

transparent to ensure that the 

transmission service provider is not 

discriminating in the provision of 

transmission service through its 

calculation of available transfer 

capability. 

89. Similarly, Requirement R1 of the 

Rated System Path Methodology (MOD– 

029–1) requires a transmission operator, 

when calculating total transfer 

capabilities for available transfer 

capability, to use a transmission model 

that meets the criteria set forth in the 

sub-requirements. Requirement R1.1.9 

allows a transmission operator to use a 

model that ‘‘models series 

compensation for each line at the 

expected operating level unless 

specified otherwise in the [available 

transfer capability implementation 

document].’’64 Requirement R1.1.10 

allows a transmission operator to use a 

model that ‘‘includes any other 

modeling requirements or criteria 

specified in the [available transfer 

capability implementation 

document].’’65

90. The same unrestrained discretion 

is found in the Flowgate Methodology 

(MOD–030–2). Requirement R2.1 

requires transmission operators to 

include flowgates used in the available 

flowgate capability based, at a 

minimum, on specified criteria. This 

criteria includes, at Requirement R2.1.3, 

any limiting element/contingency 

combination at least within the 

transmission model identified in 


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66Requirement R3.4 requires the transmission 

operator to make available to the transmission 

service provider a transmission model to determine 

available flowgate capability that contains modeling 

data and system topology for the facilities within 

its reliability coordinator’s area. Equivalent 

representation of radial lines and facilities 161kv or 

below is allowed. 

67Requirement R3.5 requires the transmission 

operator to make available to the transmission 

service provider a transmission model to determine 

available flowgate capability that contains modeling 

data and system topology (or equivalent 

representation) for immediately adjacent and 

beyond reliability coordination areas. 

68Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 292–93; Order 693, FERC Stats. & Regs. ¶ 31,242 

at P 1039. 

69MOD–001–1, Requirements R3.2, R7. NERC 

states in its filing that additional guidance from the 

Commission would be necessary in order to specify 

in greater detail a single ‘‘best’’ approach for 

treating counterflows. See NERC Filing at 101. The 

Commission did not require the development of a 

single approach for the treatment of counterflows. 

Rather, the Commission required the development 

of Reliability Standards that result in the use of 

counterflow assumptions for short-term and longterm available transfer capability calculations that 

are consistent with those used for the planning of 

operations and system expansion. See Order No. 

890, FERC Stats. & Regs. ¶ 31,241 at P 292–93; 

Order 693, FERC Stats. & Regs. ¶ 31,242 at P 1039. 

The proposed Reliability Standards adequately 

address that requirement by directing each 

transmission service provider to identify in its 

implementation document how it will address 

counterflows in its calculation of available transfer 

capability and available flowgate capacity. 

70MOD–028–1, Requirement R10; MOD–029–1, 

Requirement R7; MOD–030–2, Requirement R8. 

71Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 245; Order 693, FERC Stats. & Regs. ¶ 31,242 at 

P 1033. 

72MOD–001–1, Requirement R3.1. In its filing, 

NERC discusses several options should the 

Commission desire to impose a uniform approach 

regarding the treatment of reservations with the 

same point of receipt, but multiple points of 

delivery. See NERC Filing at 90–92. Neither Order 

No. 890 nor Order No. 693 directed that a single 

approach be adopted to account for such 

reservations and, instead, required only that 

instructions on how these reservations are 

accounted for by the transmission service provider 

be clearly laid out. See Order No. 890, FERC Stats. 

& Regs. ¶ 31,241 at P 245; Order 693, FERC Stats. 

& Regs. ¶ 31,242 at P 1033. The obligation of each 

transmission service provider to identify in its 

implementation document how they have 

implemented MOD–028–1, MOD–029–1, or MOD– 

030–2, including the calculation of existing 

transmission capacity, satisfies this requirement. 

Requirement R3.466 and R3.567 that has 

been subjected to an interconnectionwide congestion management procedure 

within the last 12 months, unless the 

limiting element/contingency 

combination is accounted for using 

another available transmission 

capability methodology. Requirement 

R2.1.4 allows transmission operators to 

consider any limiting element/ 

contingency combination within the 

transmission model that has been 

requested to be included by any other 

transmission service provider using the 

flowgate methodology or area 

interchange methodology under certain 

circumstances. 

91. In Order No. 890, the Commission 

expressed particular concern regarding 

consistency in the use of counterflow 

assumptions in short-term and longterm calculations of available transfer 

capability.68 The Reliability Standards 

achieve consistency by requiring each 

transmission service provider to identify 

in its available transfer capability 

implementation document how it 

accounts for counterflows and to 

calculate available transfer capability 

using assumptions no more limiting 

than those used in the planning of 

operations for the corresponding time 

period.69 However, the Reliability 

Standards again place no limit on the 

parameters the transmission service 

provider can use to account for 

counterflows. Under MOD–028–1, 

MOD–029–1, and MOD–030–2, 

transmission service providers are 

permitted to make adjustments to 

available transfer capability or available 

flowgate capability to reflect 

counterflows so long as such 

adjustments are allowed under the 

counterflow methodology identified in 

the available transfer capability 

implementation document.70

92. The Commission also expressed 

concern in Order No. 890 regarding the 

treatment of reservations with the same 

point of receipt (generator), but multiple 

points of delivery (load), in setting aside 

existing transmission capacity.71 The 

Commission found that such 

reservations should not be modeled in 

the existing transmission commitments 

calculation simultaneously if their 

combined reserved transmission 

capacity exceeds the generator’s 

nameplate capacity at the point of 

receipt. The Commission required the 

development of Reliability Standards 

that lay out clear instructions on how 

these reservations should be accounted 

for by the transmission service provider. 

The proposed Reliability Standards 

achieve this by requiring transmission 

service providers to identify in their 

implementation documents how they 

have implemented MOD–028–1, MOD– 

029–1, or MOD–030–2, including the 

calculation of existing transmission 

commitments.72 However, the 

Reliability Standards again place no 

limits on the parameters that each 

transmission service provider can use. 

93. The proposed Reliability 

Standards thus provide each 

transmission service provider with 

substantial discretion when 

implementing various aspects of its 

available transfer capability 

methodology. The Commission 

recognizes that there are aspects of 

calculations that require the use of 

parameters and assumptions tailored to 

the particular needs of a transmission 

service provider. In certain instances, 

however, this discretion could be used 

by a transmission service provider to 

include criteria that allow for 

discrimination in the provision of 

transmission service through 

inconsistent calculation of available 

transfer capability. For example, the use 

of parameters, modeling requirements, 

criteria, or assumptions that are 

undefined or ‘‘black box’’ in nature 

would provide the transmission service 

provider with the opportunity and 

ability to vary its calculations 

depending on the customer seeking 

service. Such discretion undermines the 

ability of the Commission and others to 

replicate and verify the results of a 

transmission service provider’s 

calculations. 

94. In order to ensure that remaining 

opportunities for undue discrimination 

are identified and eliminated, the 

Commission proposes to direct the ERO 

to conduct a review of the additional 

parameters and assumptions included 

by each transmission service provider in 

its available transfer capability 

implementation document as of the date 

the Reliability Standards become 

effective. Based on its review, NERC 

would identify in the audit required 

above those instances in which 

parameters and assumptions are not 

sufficiently specific or transparent to 

allow the Commission and others to 

replicate and verify the results of the 

transmission service provider’s 

calculation of available transfer 

capability or available flowgate 

capacity. Upon review of NERC’s 

analysis, the Commission may direct the 

ERO to develop a modification to MOD– 

001–1 to address any lack of 

transparency. The Commission seeks 

comment whether additional 

requirements should be directed in this 

proceeding to ensure that the discretion 

provided under the available transfer 

capability implementation documents 

cannot be used to unduly discriminate 

in the provision of transmission service. 

2. Capacity Benefit Margin 

Implementation Documents 

95. Second, the Commission proposes 

to direct the ERO to study whether the 

capacity benefit margin implementation 

documents developed by transmission 

service providers under MOD–004–1 

contain a level of specificity sufficient 

to allow the Commission and others to 

replicate and verify the calculation, 

allocation, and use of capacity benefit 

margin by transmission service 

providers. As explained above, capacity 


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Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 12761 

73The scope of this audit should not include 

review of the studies supporting requests for 

capacity benefit margin. The Commission agrees 

with NERC that it would be inappropriate to place 

a functional entity, such as the transmission service 

provider, in the position of having to judge the 

quality of a study supporting a customer’s request 

for capacity benefit margin. Requirements R3 and 

R4 of MOD–004–1 identify the specific kinds of 

studies that must be performed and supporting 

information that is to be maintained when 

determining a need for capacity benefit margin. 

Compliance with these requirements can be audited 

by NERC and the regional entities in the normal 

course of their compliance review. See Guidance 

Order on Compliance Audits Conducted by the 

Electric Reliability Organization and Regional 

Entities, 126 FERC ¶ 61,038 (2009). 

74NERC Filing at 97. 

75 Id. 

76Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 275; Order No. 693, FERC Stats. & Regs. ¶ 31,242 

at P 1122–23, 1126. 

77MOD–008–1, Requirement R1. 

benefit margin is the amount of firm 

transmission capability preserved by the 

transmission service provider for loadserving entities, whose loads are located 

on that transmission service provider’s 

system, to enable access by the loadserving entities to generation from 

interconnected systems to meet 

generation reliability requirements. As 

NERC explained in its filing, various 

entities have already developed 

methodologies for determining capacity 

benefit margin. Accordingly, NERC 

proposed a Reliability Standard that 

allows transmission service providers 

flexibility in choosing an appropriate 

methodology for calculating, allocating 

and using capacity benefit margins. 

Although MOD–004–1 specifies core 

elements that should be consistent 

among all methodologies, the 

transmission service provider has 

discretion to use any methodology to 

calculate, allocate, and use capacity 

benefit margins, provided that it is 

identified and described in the 

implementation document. 

96. For example, Requirements R5.1 

and R6.1 of MOD–004–1 require the 

transmission service provider to 

establish capacity benefit margin values 

for each path and flowgate reflecting 

consideration of studies provided by 

load-serving entities and resource 

planners demonstrating a need for 

capacity benefit margin and applicable 

reserve margin or resource adequacy 

requirements. Although Requirement 

R1.2 requires the transmission service 

provider to identify in its capacity 

benefit margin implementation 

document the procedures and 

assumptions for establishing these path 

and flowgate values, the Reliability 

Standard places no limitations or 

parameters on those procedures or 

assumptions. As with MOD–001–1, 

MOD–004–1 would permit the 

transmission service provider to adopt 

procedures and assumptions that are not 

sufficiently transparent to ensure that 

the transmission provider is similarly 

treating similarly-situated customers. 

The Commission is therefore concerned 

that the Reliability Standard could be 

implemented by a transmission service 

provider in a way that allows for undue 

discretion in the provision of 

transmission service. 

97. In order to ensure that remaining 

opportunities for undue discrimination 

are identified and eliminated, the 

Commission proposes to direct the ERO 

to conduct a review of the procedures 

and assumptions included by each 

transmission service provider in its 

capacity benefit margin implementation 

document as of the date the Reliability 

Standards become effective. Based on its 

review, NERC would identify in the 

audit required above those instances in 

which additional procedures and 

assumptions are not sufficiently specific 

or transparent to allow the Commission 

and others to replicate and verify the 

calculation, allocation and use of 

capacity benefit margin by the 

transmission service provider.73 Upon 

review of NERC’s analysis, the 

Commission may direct the ERO to 

develop a modification to MOD–004–1 

to address any lack of transparency. The 

Commission seeks comment whether 

additional requirements should be 

directed in this proceeding to ensure 

that the discretion provided under the 

capacity benefit margin implementation 

documents cannot be used to unduly 

discriminate in the provision of 

transmission service. 

3. Transmission Reliability Margin 

Implementation Documents 

98. Finally, the Commission proposes 

to direct the ERO to study whether the 

transmission reliability margin 

implementation documents developed 

by each transmission operator under the 

Reliability Standards contain a level of 

specificity sufficient to allow the 

Commission and others to replicate and 

verify the calculation and use of 

transmission reliability margin. 

Transmission reliability margin is 

transmission transfer capability set 

aside to mitigate risks to operations, 

such as deviations in dispatch, load 

forecast, outages, and similar such 

conditions. As NERC explains in its 

filing, transmission reliability margin is 

a subjective quantity as it is almost 

entirely based on the principles of risk 

management and risk tolerance, which 

vary from entity to entity.74 Therefore, 

although MOD–008–1 identifies the 

particular categories of uncertainty that 

transmission operators may consider 

when establishing transmission 

reliability margin, the transmission 

operator is permitted to use any 

methodology to calculate, allocate, and 

use transmission reliability margins, 

provided that it is identified and 

described in the implementation 

document. 

99. NERC states in its filing that 

guidance from the Commission would 

be necessary in order to specify in 

greater detail a single ‘‘best’’ 

methodology to govern the calculation 

of a maximum transmission reliability 

margin.75 The Commission does not 

believe that it is necessary to establish 

a single methodology for calculating, 

allocating and using transmission 

reliability margin. In Order Nos. 890 

and 693, the Commission directed 

NERC to clarify how transmission 

reliability margin should be calculated 

and allocated across paths or flowgates 

and how to establish an appropriate 

maximum transmission reliability 

margin.76 The Commission directed 

NERC to specify the parameters for 

entities to use in determining 

uncertainties for which transmission 

reliability margin can be set aside and 

used. The Commission also directed the 

ERO to modify its Reliability Standards 

to prevent the use of capacity benefit 

margin and transmission reserve margin 

for the same purposes (i.e. double 

counting). The proposed Reliability 

Standard accomplishes these directives 

by requiring each transmission operator 

to identify in its transmission reliability 

margin implementation document the 

components that will be used to 

calculate transmission reliability 

margin, how those components will be 

used, and how resulting transmission 

reliability margin values will be 

allocated across paths or flowgates.77

This level of detail satisfies the 

requirements of Order No. 890 and 

related directives of Order No. 693 by 

making each transmission operator’s 

transmission reliability margin 

methodologies transparent. 

100. However, as with MOD–001–1 

and MOD–004–1, the Commission is 

concerned that MOD–008–1 could be 

implemented by a transmission operator 

in a way that allows for undue 

discrimination in the provision of 

transmission service. For example, 

Requirements R1.1 and R1.2 of MOD– 

008–1 require each transmission 

operator to include in its transmission 

reliability margin implementation 

document the components of 

uncertainty used in establishing a 

transmission reliability margin, a 

description of how those components 


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12762 Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 

are used in the calculation of 

transmission reliability margin, and a 

description of how transmission 

reliability margin is allocated across 

paths or flowgates. The transmission 

reliability margin implementation 

document developed by transmission 

operators could include parameters, 

modeling requirements, criteria or 

assumptions that are insufficiently 

transparent, providing the transmission 

operator the opportunity and ability to 

vary its calculations depending on the 

customer requesting transmission 

service. 

101. In order to ensure that remaining 

opportunities for undue discrimination 

are identified and eliminated, the 

Commission proposes to direct the ERO 

to conduct a review of the procedures 

identified in each transmission 

operator’s transmission reserve margin 

implementation document as of the date 

the Reliability Standards become 

effective. Based on its review, NERC 

would identify in the audit required 

above those instances in which 

procedures, criteria, or assumptions are 

not sufficiently specific or transparent 

to allow the Commission and others to 

replicate and verify the results of the 

transmission operator’s calculation of 

transmission reserve margin. Upon 

review of NERC’s analysis, the 

Commission may direct the ERO to 

develop a modification to MOD–008–1 

to address any lack of transparency. The 

Commission seeks comment whether 

additional requirements should be 

directed in this proceeding to ensure 

that the discretion provided under the 

transmission reserve margin 

implementation documents cannot be 

used to unduly discriminate in the 

provision of transmission service. 

B. Proposed Modifications of the 

Reliability Standards 

102. While the Commission generally 

proposes to approve the Reliability 

Standards as in compliance with Order 

No. 890 and the related directives of 

Order No. 693, the Commission also 

proposes to direct the ERO to develop 

modifications of the Reliability 

Standards to comply with the following 

discrete issues: The availability of each 

transmission service provider’s 

implementation documents; the 

consistent treatment of assumptions in 

the calculation of available transfer 

capability; the calculation, allocation 

and use of capacity benefit margin; the 

calculation of total transfer capability 

under the Rated System Path 

Methodology; and, the treatment of 

network resource designations in the 

calculation of available transfer 

capability. Each of these issues is 

discussed below. 

1. Availability of Implementation 

Documents 

a. NERC Proposal 

103. The proposed Reliability 

Standards require that the available 

transfer capacity, capacity benefit 

margin, and transmission reliability 

margin implementation documents be 

made available to specified entities. 

Requirement R4 of MOD–001–1 requires 

that the following entities have access to 

the available transfer capability 

implementation document: Each 

planning coordinator, reliability 

coordinator, and transmission operator 

associated with the transmission service 

provider’s area; and each planning 

coordinator, reliability coordinator, and 

transmission service provider adjacent 

to the transmission service provider’s 

area. Requirement R2 of MOD–004–1 

requires each transmission service 

provider to make its capacity benefit 

margin implementation document 

available to transmission operators, 

transmission service providers, 

reliability coordinators, transmission 

planners, resource planners, and 

planning coordinators that are within or 

adjacent to the transmission service 

provider’s area, and to load-serving 

entities and balancing authorities within 

the transmission service provider’s area. 

Requirement R3 of MOD–008–1 requires 

each transmission operator to provide 

its transmission reliability 

implementation document upon request 

by transmission service providers, 

reliability coordinators, transmission 

planners, and transmission operators. 

NERC states that it and NAESB have 

agreed that requirements for making 

information available to other entities 

are more appropriately addressed 

through the NAESB process. 

b. Commission Proposal 

104. The Commission is concerned 

that the proposed Reliability Standards 

potentially restrict the disclosure of the 

available transfer capability, capacity 

benefit margin, and transmission 

reliability margin implementation 

documents. NERC does not explain in 

its filings why only certain entities 

would have access to these materials, 

nor why the specified list of recipients 

varies for each document. While the 

Commission notes that the proposed 

NAESB standards accompanying the 

Reliability Standards would require 

transmission service providers to post a 

link to the implementation documents 

on their OASIS, which would result in 

disclosure beyond the specified entities 

listed in the Reliability Standards, the 

Commission believes that it is important 

for reliability purposes to require 

disclosure of the implementation 

documents to a broader audience than 

provided in the Reliability Standards. 

The Commission’s jurisdiction under 

section 215 of the FPA is broader than 

our jurisdiction to require compliance 

with the NAESB standards under 

sections 205 and 206 of the FPA. These 

documents will describe how the 

transmission provider will implement 

the Reliability Standards and, therefore, 

should be disclosed by all transmission 

service providers, not only those who 

are also public utilities. 

105. Therefore, to ensure sufficient 

transparency, the Commission proposes 

to direct the ERO, pursuant to section 

215(d)(5) of the FPA and section 35.19(f) 

of our regulations, to modify the 

proposed Reliability Standards to make 

the available transfer capability, 

capacity benefit margin, and 

transmission reliability margin 

implementation documents available to 

all customers eligible for transmission 

service in a manner that is consistent 

with relevant NAESB standards. The 

Commission seeks comment on any 

improvements that may be necessary to 

improve access by transmission 

customers to the implementation 

documents. 

2. Consistent Treatment of Assumptions 

a. NERC Proposal 

106. Under each of the methodologies 

contained in the proposed Reliability 

Standards, available transfer capability 

is calculated as total transfer capability 

minus existing transmission 

commitments, capacity benefit margin, 

and transmission reliability margin, 

plus postbacks and counterflows. NERC 

contends that the Reliability Standards 

work together to ensure that similar 

risks will not be double counted in the 

calculation of capacity benefit margin 

and transmission reliability margin. 

Specifically, Requirement R2 of MOD– 

008–1 prohibits a transmission operator 

from including any of the components 

of capacity benefit margin in the 

components of uncertainty used to 

calculate transmission reliability 

margin. NERC contends that MOD–004– 

1 addresses this prohibition by 

describing the specific type of studies 

and requirements that may be used to 

determine a need for capacity benefit 

margin. 

b. Commission Proposal 

107. The Commission is concerned 

that proposed Reliability Standards do 

not preclude a transmission service 


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Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 12763 

78Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 1080. see also Order No. 890, FERC Stats. & Regs. 

¶ 31,241 at P 259; Order No. 890–A, FERC Stats. & 

Regs. ¶ 31,261 at P 82. 

provider from using data and 

assumptions in a way that double 

counts their impact on available transfer 

capability and thereby skews the 

amount of capacity made available to 

others. NERC states that MOD–004–1 

and MOD–008–1 have been drafted to 

preclude the double counting of similar 

risks in the calculation of capacity 

benefit margin and transmission 

reliability margin. However, other 

components of the available transfer 

capability calculation could be affected 

by the same data or assumptions, and 

there is no apparent restriction in the 

Reliability Standards from such data or 

assumptions in a way that double 

counts their impact on available transfer 

capability. 

108. For example, the Reliability 

Standards would appear to allow the 

transmission service provider to factor a 

reserve margin for facility outages into 

more than one of the components of the 

available transfer capability calculation. 

If the effect of the reserve margin were 

to appear in multiple components of the 

available transfer capability calculation 

in a similar way, under certain 

modeling approaches the results of that 

calculation would be skewed. While it 

may be appropriate for some variables to 

be factored into multiple components of 

the available transfer capability 

calculation, such as facility ratings, the 

Reliability Standards do not require that 

assumptions affecting multiple 

components of the available transfer 

capability calculation are implemented 

in a way that is consistent with their 

actual effect on available transfer 

capability. The Commission proposes to 

direct the ERO, pursuant to section 

215(d)(5) of the FPA and section 35.19(f) 

of our regulations, to modify the 

proposed Reliability Standards to 

ensure that the proposed Reliability 

Standards preclude a transmission 

service provider from using data and 

assumptions in a way that double 

counts their impact on available transfer 

capability and thereby skews the 

amount of capacity made available to 

others. 

3. Capacity Benefit Margin (MOD–004– 

1) 

a. NERC Proposal 

109. As noted above, Requirements 

R5.1 and R6.1 of MOD–004–1 require 

transmission service providers to 

establish capacity benefit margin values 

for each path and flowgate ‘‘reflect[ing] 

consideration of’’ both (i) studies 

provided by load-serving entities and 

resource planners demonstrating a need 

for capacity benefit margin and (ii) 

applicable reserve margin or resource 

adequacy requirements. In preparing 

their studies, Requirements R3.1 and 

R4.1 direct load-serving entities and 

resource planners to use one or more of 

the following to determine the 

generation capability import 

requirement: (i) Loss of load expectation 

studies, (ii) loss of load probability 

studies, (iii) deterministic risk-analysis 

studies, and (iv) applicable reserve 

margin or resource adequacy 

requirements. With regard to the 

allocation and use of transmission 

capacity set aside as capacity benefit 

margin, Requirement R1.3 requires the 

transmission service provider to include 

in its capacity benefit margin 

implementation document the 

procedure for a load-serving entity or 

balancing authority to use transmission 

capacity set aside as capacity benefit 

margin, including the manner in which 

the transmission service provider ‘‘will 

manage’’ situations where the requested 

use of capacity benefit margin exceeds 

the capacity benefit margin available. 

b. Commission Proposal 

110. In Order Nos. 890 and 693, the 

Commission emphasized that each loadserving entity has the right to request 

that capacity benefit margin be set aside, 

and to use transmission capacity set 

aside for that purpose, to meet its 

verifiable generation reliability criteria 

requirement.78 The Commission is 

concerned that, as proposed, the 

Reliability Standard would allow a 

transmission service provider to 

calculate, allocate, and use capacity 

benefit margin in a way that impairs the 

reliable operation of the Bulk-Power 

System. Under the Reliability Standard, 

the transmission service provider is to 

‘‘reflect consideration’’ of studies 

provided by load-serving entities and 

resource planners demonstrating a need 

for capacity benefit margin and 

‘‘manage’’ situations where the 

requested use of capacity benefit margin 

exceeds the capacity benefit margin 

available. The Reliability Standard 

places no bounds on this 

‘‘consideration’’ and ‘‘management’’ 

and, for example, would permit a 

transmission service provider to make 

decisions regarding the use of capacity 

benefit margin based solely on 

economic considerations 

notwithstanding a demonstration of 

need for capacity benefit margin by a 

load-serving entity or resource planner. 

The Commission proposes, pursuant to 

section 215(d)(5) of the FPA and section 

39.5(f) of our regulations, to direct the 

ERO to develop a modification to the 

Capacity Benefit Margin Methodology 

(MOD–004–1) to ensure that the 

Reliability Standard would not allow a 

transmission service provider to 

calculate, allocate, and use capacity 

benefit margin in a way that impairs the 

reliable operation of the Bulk-Power 

System. 

111. In addition, the Commission has 

concern regarding references to 

applicable reserve margin and resource 

adequacy requirements in the 

determination of the generation 

capability import requirements by loadserving entities and resource planners 

under Requirements R3.1 and R4.1. 

Under the phrasing of those provisions, 

load-serving entities and resource 

planners must determine their 

generation capability import 

requirement by using one or more of 

loss of load expectation studies, loss of 

load probability studies, deterministic 

risk-analysis studies, and applicable 

reserve margin or resource adequacy 

requirements. As a result, a load-serving 

entity or resource planner could rely 

solely on reserve margin and resource 

adequacy requirements to demonstrate a 

need for capacity benefit margin 

without any analysis of loss of load 

expectations, loss of load probabilities, 

or deterministic risk. In comparison, 

Requirements 5.1 and 6.1 obligate the 

transmission service provider to 

consider both the studies provided by 

load-serving entities and resource 

planners and applicable reserve margin 

and resource adequacy requirements 

when calculating capacity benefit 

margin and allocating it to particular 

paths or flowgates. The Commission 

proposes, pursuant to section 215(d)(5) 

of the FPA and section 39.5(f) of our 

regulations, to direct the ERO to develop 

a modification to MOD–004–1 to require 

load-serving entities and resource 

planners to determine generation 

capability import requirements by 

reference to relevant studies and 

applicable reserve margin or resource 

adequacy requirements, as relevant. 

4. Calculation of Total Transfer 

Capability Under the Rated System Path 

Methodology (MOD–029–1) 

a. NERC Proposal 

112. Requirement R2 of the Rated 

System Path Methodology (MOD–029– 

1) provides the process a transmission 

operator must use to determine total 

transfer capability. Requirement R2.7 of 

that Reliability Standard requires the 

transmission operator to set the total 

transfer capability of an available 

transfer capability path to a value 


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79Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 237. 

80Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 

at P 105. 

81See MOD–028–001, Requirement R8; MOD– 

029–1, Requirement R5; MOD–030–2, Requirement 

R6.1. 

82Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 1041. 

83The specific definitions of high, medium and 

lower are provided in North American Electric 

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

on reh’g, 120 FERC ¶ 61,145 (2007) (Violation Risk 

Factor Rehearing Order). 

84The 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. The Commission also 

explained that this list was not necessarily allinclusive and that it retained the flexibility to 

consider additional guidelines in the future. A 

detailed explanation is provided in the Violation 

Risk Factor Rehearing Order, 120 FERC ¶ 61,145 at 

P 8–13. 

determined prior to 1994 in certain 

instances: 

R2.7. For available transfer capability Paths 

whose path rating, adjusted for seasonal 

variance, was established, known and used 

in operation since January 1, 1994, and no 

action has been taken to have the path rated 

using a different method, set the total transfer 

capability at that previously established 

amount. 

b. Commission Proposal 

113. In Order No. 890, the 

Commission required the use of 

consistent practices to calculate total 

transfer capability.79 In Order No. 890– 

A, the Commission clarified that, while 

total transfer capability need not be 

recalculated at consistent time intervals, 

the transmission operator should 

consider whether any changes in system 

topology, contingency outages, or other 

factors are substantial enough to merit 

recalculation of total transfer 

capability.80

114. NERC has not explained the 

inclusion of Requirement R2.7 in the 

Rated System Path Methodology. It is 

not clear to the Commission why certain 

applicable entities would be required to 

use pre-1994 total transfer capability 

values. The Commission is concerned 

that requiring pre-1994 total transfer 

capability values to remain in place 

without adequate explanation 

essentially exempts certain paths from 

the total transfer capability 

requirements in the Rated System Path 

Methodology and may result in total 

transfer capability values that are 

incorrectly based on stale assumptions 

and criteria. 

115. While the Commission proposes 

to approve the proposed Reliability 

Standard overall as just and reasonable 

and an improvement on available 

transfer capability transparency, as 

discussed above, pursuant to section 

215(d)(5) of the FPA and section 39.5(f) 

of our regulations, the Commission 

seeks comment on whether it should 

direct the ERO to develop a 

modification to the Rated System Path 

Methodology (MOD–029–1) to remove 

Requirement R2.7 as unsupported. 

5. Treatment of Network Resource 

Designations 

a. NERC Proposal 

116. In each of the proposed 

Reliability Standards, transmission 

service providers are required to 

identify as part of their calculation of 

existing transmission commitments the 

amount of capacity that is set aside for 

network integration transmission 

service.81 However, the specificity of 

that requirement varies among the 

proposed Reliability Standards. 

117. Under the Flowgate Methodology 

(MOD–030–2), Requirements R6.1 and 

6.2 provide for calculation of the impact 

of network integration transmission 

service based on a modeling of load 

forecasts for the time period being 

calculated and unit commitment and 

dispatch order, including all designated 

network resources and other resources 

that are committed or have the legal 

obligation to run as specified in the 

transmission service provider’s 

implementation document. Requirement 

R8 of the Area Interchange Methodology 

(MOD–028–1) and Requirement R5 of 

the Rated System Path Methodology 

(MOD–029–1) provide for the inclusion 

of firm capacity reserved for network 

integration transmission service, but do 

not describe how the transmission 

service provider is to identify that 

amount of capacity. 

118. With regard to the frequency of 

these calculations, Requirement R8 of 

MOD–001–1 would require every 

transmission service provider 

calculating available transfer capability 

to perform recalculations of available 

transfer capability at specified 

frequencies, unless none of the 

calculated values identified in the 

available transfer capability equation 

have changed. 

b. Commission Proposal 

119. In Order No. 693, the 

Commission directed the ERO to 

develop requirements specifying how 

transmission service providers should 

determine which generators should be 

modeled in service when calculating 

available transfer capability.82 Among 

other things, the Commission directed 

the ERO to revise the Reliability 

Standards to specify that base 

generation dispatch schedules will 

reflect the modeling of all designated 

network resources and other resources 

that are committed to or have the legal 

obligation to run, as they are expected 

to run. The Commission also directed 

transmission service providers to 

address the effect on available transfer 

capability of designating and 

undesignating a network resource. 

120. NERC has not explained the 

failure to include in each of the 

available transfer capability 

methodologies a requirement that base 

generation dispatch schedules will 

reflect the modeling of all designated 

network resources and other resources 

that are committed to or have the legal 

obligation to run, as they are expected 

to run. It is therefore unclear whether 

the proposed Reliability Standards 

address the effect on available transfer 

capability of designating and 

undesignating a network resource. 

While the Commission proposes to 

approve the proposed Reliability 

Standards as just and reasonable and an 

improvement on available transfer 

capability transparency, pursuant to 

section 215(d)(5) of the FPA and section 

39.5(f) of our regulations, the 

Commission proposes to direct the ERO 

to develop a modification to the 

Reliability Standards to address these 

requirements. 

C. Violation Risk Factors and Violation 

Severity Levels 

121. To determine a base penalty 

amount for a violation of a requirement 

within a Reliability Standard, NERC 

must first determine an initial range for 

the base penalty amount. To do so, 

NERC will assign a violation risk factor 

for each requirement of a Reliability 

Standard that relates to the expected or 

potential impact of a violation of the 

requirement on the reliability of the 

Bulk-Power System. For that 

requirement, the ERO assigns a lower, 

medium or high violation risk factor for 

each mandatory Reliability Standard 

requirement.83 The Commission has 

established guidelines for evaluating the 

validity of each violation risk factor 

assignment.84

122. NERC will also define up to four 

violation severity levels—lower, 

moderate, high and severe—as 

measurements for the degree to which 

the requirement was violated in a 

specific circumstance. For a specific 

violation of a particular requirement, 

NERC or the Regional Entity will 

establish the initial value range for the 

base penalty amount by finding the 

intersection of the applicable violation 


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Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 12765 

85North American Electric Reliability Corp., 123 

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

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

¶ 61,212 (2008). 

86The MOD–010 through MOD–025 Reliability 

Standards establish data requirements, reporting 

procedures, and system model development and 

Continued 

risk factor and violation severity level in 

the base penalty amount table in 

appendix A of its sanction guidelines. 

123. On June 19, 2008, the 

Commission issued an order 

establishing four guidelines for the 

development of violation severity 

levels.85 First, the violation severity 

level assignments should not have the 

unintended consequence of lowering 

the current level of compliance. Second, 

the violation severity levels should 

ensure uniformity and consistency in 

the determination of penalties. Third, a 

violation severity level assignment 

should be consistent with the 

corresponding requirement. Fourth, a 

violation severity level assignment 

should be based on a single violation, 

not on a cumulative number of 

violations. 

1. NERC Proposal 

124. In its August 29, 2008 filing, 

NERC proposes violation severity levels 

that are specific to the individual 

requirements of the proposed Reliability 

Standards. NERC states that it 

developed violation severity level 

assignments for MOD–001–1, MOD– 

008–1, MOD–028–1, MOD–029–1, and 

MOD–030–1 prior to issuance of the 

Violation Severity Level Order. As a 

result, NERC states that it has not 

analyzed the proposed violation severity 

levels relative to the Commission’s 

guidelines established in the Violation 

Severity Level Order. 

125. In addition, NERC states that it 

is not filing the associated violation risk 

factors with these Reliability Standards. 

While violation risk factors have been 

developed and balloted for each of the 

five proposed Reliability Standards, 

NERC states that its Board believes 

further review of the violation risk 

factors is warranted given recent 

Commission actions in general and the 

development history of these violation 

risk factors in particular. In accordance 

with its Rules of Procedure, NERC states 

that it will submit violation risk factors 

for these proposed Reliability Standards 

in a future filing. 

126. NERC states that each balloted 

Reliability Standard included a 

violation risk factor for each main 

requirement in the Reliability Standard. 

For all the requirements in the balloted 

MOD Reliability Standards, the 

applicable violation risk factors were 

‘‘lower.’’ In developing the violation 

risk factor assignments, NERC states that 

there were opposing viewpoints with 

respect to the appropriate assignments. 

According to NERC, one view offered 

that available transfer capability and its 

associated methodologies do not 

directly affect the electrical state of the 

system or the ability to monitor or 

control it as would be required under 

the ‘‘medium’’ violation risk factor 

assignment. NERC states that an 

incorrect available transfer capability 

calculation may lead to oversubscribing 

or undersubscribing the system. 

According to NERC, undersubscribing, 

while affecting the potential for 

commercial activity, actually benefits 

reliability. Oversubscribing the system 

as a result of an optimistic available 

transfer capability value, while 

somewhat beneficial to commercial 

activity, may lead to a reliability 

concern that if realized can be managed 

by the operator’s adherence to system 

limits, to the extent that the operator has 

options to implement some measure of 

transmission loading relief to reduce 

flows due to transactions. NERC states 

that for an incorrect available transfer 

capability to become a reliability issue 

requires an optimistic available transfer 

capability value, coupled with the sale 

of that available transfer capability, and 

an operator who is not mindful to the 

system limits, the last of which is 

governed by other transmission operator 

and interconnection operating 

Reliability Standards. On this argument, 

according to NERC, assigning a 

‘‘medium’’ violation risk factor due to 

the ‘‘direct’’ impact is questionable. 

127. On this basis, the drafting team 

evaluated the scope of the remaining 

work to meet the Commission deadline 

and focused its attention to the 

technical issues, adjusting the violation 

risk factors to ‘‘lower’’ based on the 

industry comments and the arguments 

presented above. However, NERC states 

that its Board believes that a more 

thorough review of the violation risk 

factors is warranted given recent 

Commission actions in general and the 

development history of these violation 

risk factors in particular. NERC’s board 

has asked NERC staff to review these 

violation risk factors through an open 

stakeholder process to ensure that they 

are consistent with the intent of the 

violation risk factor definitions and 

prior Commission decisions on 

violation risk factors. Accordingly, 

NERC states that it is not filing the 

associated violation risk factors with 

these Reliability Standards at this time. 

NERC states that it will submit violation 

risk factors for these proposed 

Reliability Standards in a future filing. 

128. In its November 21, 2008 and 

March 6, 2009 filings, NERC proposes 

violations severity levels for MOD–004– 

1 and MOD–030–2, respectively. Similar 

to the violation severity levels proposed 

for MOD–001–1, MOD–008–1, MOD– 

028–1, MOD–029–1, and MOD–030–1, 

NERC does not propose any violation 

severity levels for the sub-requirements. 

In addition, NERC states that its board 

of trustees deferred action on the 

violation risk factors associated with 

these Reliability Standards and asked 

that they be reviewed through an open 

stakeholder process, with a report back 

to the board, to ensure that they are 

consistent with the intent of the 

violation risk factor definitions and 

Commission precedent. NERC states 

that it will submit violation risk factors 

for these Reliability Standards in a 

future filing. 

2. Commission Proposal 

129. The Commission proposes to 

accept NERC’s commitment to file 

violation severity levels and violation 

risk factors at a later time. The Violation 

Severity Level Order was issued after 

NERC developed the violation severity 

level assignments for the Reliability 

Standards at issue in this proceeding. 

As a result, NERC was unable to 

evaluate and modify the proposed 

violation severity levels to comply with 

our guidelines prior to filing the 

proposed Reliability Standards. The 

Commission proposes to direct the ERO 

to reevaluate the violation severity 

levels associated with all of the 

proposed Reliability Standards based on 

the Commission’s guidelines outlined in 

the Violation Severity Level Order and 

prepare appropriate revisions. In 

addition, the Commission proposes to 

accept NERC’s proposal to allow NERC 

staff to review the violation risk factors 

through an open stakeholder process to 

ensure that they are consistent with the 

intent of the violation risk factor 

definitions and guidance provided in 

the Violation Risk Factor Order and the 

Violation Risk Factor Rehearing Order. 

The Commission proposes to direct 

NERC to file revised violation severity 

levels and violation risk factors no later 

than 120 days before the Reliability 

Standards become effective. 

D. Disposition of Other Reliability 

Standards 

1. MOD–010–1 through MOD–025–1 

130. Order No. 890 directed public 

utilities, working through NERC, to 

modify the reliability standards MOD– 

010 through MOD–025 86 to incorporate 


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12766 Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 

validation for use in the reliability analysis of the 

interconnected transmission systems. 

87Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 290. 

88Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 206. 89See MOD–001–1, Requirement R2.3. 

90Order No. 693, FERC Stats. & Regs. ¶ 31,242 at 

P 777. 91 Id. P 782. 92 Id. P 779, 782. 93See MOD–028–1, Requirements R3 and R4; 

MOD–029–1, Requirements R2 and R3; MOD–030– 

2, Requirement R2.4. 

a requirement for the periodic review 

and modification of models for (1) load 

flow base cases with contingency, 

subsystem, and monitoring files, (2) 

short circuit data, and (3) transient and 

dynamic stability simulation data, in 

order to ensure that they are up to date. 

The Commission found that this 

requirement is essential in order to have 

an accurate simulation of the 

performance of the grid and from which 

to comparably calculate available 

transfer capability, therefore increasing 

transparency and decreasing the 

potential for undue discrimination by 

transmission service providers.87

a. NERC Proposal 

131. NERC states that this modeling 

activity is outside the scope of the 

available transfer capability Reliability 

Standards drafting team effort because it 

requires a different skill set and 

expertise than that required for 

developing available transfer capability 

and should be addressed by a separate 

drafting team. NERC states that these 

Reliability Standards are part of its 

Reliability Standards Development Plan. 

NERC states that this is consistent with 

Order No. 693, which identified nine 

Reliability Standards, none of which 

were MOD–010 through MOD–025, as 

the core of the available transfer 

capability initiative directed in Order 

No. 890.88

b. Commission Proposal 

132. The Commission proposes to 

allow NERC to address revisions to 

MOD–010 through MOD–025 through a 

separate project. Those Reliability 

Standards are generally intended to 

establish consistent data requirements, 

reporting procedures and system models 

for use in reliability analysis. As such, 

the Commission proposes to find that 

NERC is correct that they were not a 

part of the available transfer capability 

modifications required in Order Nos. 

890 and 693. 

2. Reliability Standards Proposed To Be 

Retired or Withdrawn 

a. NERC Proposal 

133. NERC requests that FAC–013–1, 

MOD–006–0, and MOD–007–0 be 

retired when the available transfer 

capability-related Reliability Standards 

become effective. In addition, NERC 

requests to withdraw its request for 

approval of the following Reliability 

Standards that were neither approved 

nor remanded in Order No. 693, 

effective upon approval of the available 

transfer capability-related MOD 

Reliability Standards in this proceeding: 

FAC–012–1, MOD–001–0, MOD–002–0, 

MOD–003–0, MOD–004–0, MOD–005– 

0, MOD–008–0, and MOD–009–0. 

According to NERC, these Reliability 

Standards are wholly superseded by the 

MOD Reliability Standards addressed in 

this proceeding. 

b. Commission Proposal 

134. The Commission proposes to 

approve NERC’s request to retire MOD– 

006–0 and MOD–007–0 and to 

withdraw its request for approval of 

MOD–001–0, MOD–002–0, MOD–003– 

0, MOD–004–0, MOD–005–0, MOD– 

008–0, and MOD–009–0. The 

Commission also proposes to find that 

MOD–001–0, MOD–002–0, MOD–003– 

0, MOD–004–0, MOD–005–0, MOD– 

008–0, and MOD–009–0 are all 

superseded by the available transfer 

capability calculations required by the 

proposed MOD Reliability Standards in 

this proceeding and are, upon the 

effectiveness of the proposed MOD 

Reliability Standards, no longer 

necessary. 

135. With regard to FAC–012–1 and 

FAC–013–1, the Commission disagrees 

with NERC that these Reliability 

Standards are wholly superseded by the 

MOD Reliability Standards addressed in 

this proceeding. Under FAC–012–1, 

reliability coordinators and planning 

authorities would be required to 

document the methodology used to 

establish inter-regional and intraregional transfer capabilities and to state 

whether the methodology is applicable 

to the planning horizon or the operating 

horizon. Under FAC–013–1, reliability 

coordinators and planning authorities 

are required to establish a set of interregional and intra-regional transfer 

capabilities that are consistent with the 

methodology documented under FAC– 

012–1, which could require the 

calculation of transfer capabilities for 

both the planning horizon and the 

operating horizon. In comparison, the 

proposed MOD Reliability Standards 

provide only for the calculation of 

available transfer capability and its 

components, including total transfer 

capability, in the operating horizon.89

The proposed MOD Reliability 

Standards do not govern the calculation 

of transfer capabilities in the planning 

horizon, i.e., beyond 13 months in the 

future. 

136. In Order No. 693, the 

Commission approved FAC–013–1, but 

declined to approve or remand FAC– 

012–1. The Commission expressed 

concern that FAC–012–1 merely 

required the documentation of a transfer 

capability methodology without 

providing a framework for that 

methodology including data inputs and 

modeling assumptions.90 The 

Commission also expressed concern that 

the criteria used to calculate transfer 

capabilities for use in determining 

available transfer capability must be 

identical to those used in planning and 

operating the system.91 The 

Commission directed the ERO to modify 

FAC–012–1 to provide a framework for 

the transfer capability calculation 

methodology that takes account of the 

need for consistency in the criteria used 

to calculate transfer capabilities.92

137. The available transfer capability 

methodologies set forth in MOD–028–1, 

MOD–029–1, and MOD–030–2 each 

provide a framework for the calculation 

of total transfer capability and total 

flowgate capability that specifies certain 

data inputs and modeling assumptions 

to be used.93 Requirement R7 of MOD– 

001–1 also provides that, when 

calculating available transfer capability 

or available flowgate capability, the 

transmission provider shall use 

assumptions no more limiting than 

those used in the planning of operations 

for the corresponding time period 

studied. It therefore appears that the 

MOD Reliability Standards provide a 

framework for the consistent calculation 

of total transfer capability for the 

operating horizon. However, NERC has 

not addressed the requirements of Order 

No. 693 with regard to the calculation 

of transfer capabilities in the planning 

horizon. 

138. The Commission therefore 

proposes not to grant NERC’s request to 

withdraw FAC–012–1, nor approve the 

retirement of FAC–013–1. Instead, the 

Commission proposes, pursuant to 

section 215(d)(5) of the FPA and section 

39.5(f) of our regulations, to direct the 

ERO to submit a revised FAC–012–1 

and a modification to FAC–013–1 to 

comply with the relevant directives of 

Order No. 693 and as otherwise 

necessary to make the requirements of 

those Reliability Standards consistent 

with those of the proposed MOD 

Reliability Standards and the final rule 

in this proceeding. The Commission 

proposes to direct the ERO to submit a 

revised FAC–012–1 and a modification 


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Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 12767 

94These include Available Transfer Capability 

and Flowgate. 

95See 18 CFR 37.6(b)(1) (2008). 

to FAC–013–1, as well as violation 

severity levels and violation risk factors 

for FAC–012–1 and FAC–013–1, no later 

than 120 days before the MOD 

Reliability Standards become effective. 

E. Definitions 

139. In Order Nos. 890 and 693, the 

Commission noted that there was not a 

definition of available flowgate 

capability/total flowgate capability in 

the ERO’s glossary and directed the ERO 

to develop available flowgate capability/ 

total flowgate capability definitions 

used to identify a particular set of 

transmission facilities as flowgates. 

1. NERC Proposal 

140. NERC proposes to modify its 

Glossary of Terms to add the following 

twenty definitions that are used in the 

five proposed Reliability Standards, two 

of which wholly replace existing terms 

in the Commission-approved NERC 

Glossary: 94

Area Interchange Methodology: The Area 

Interchange Methodology is characterized by 

determination of incremental transfer 

capability via simulation, from which Total 

Transfer Capability (TTC) can be 

mathematically derived. Capacity Benefit 

Margin (CBM), Transmission Reliability 

Margin (TRM), and Existing Transmission 

Commitments (ETC) are subtracted from the 

TTC, and Postbacks and counterflows are 

added, to derive Available Transfer 

Capability (ATC). Under the Area 

Interchange Methodology, TTC results are 

generally reported on an area to area basis. 

ATC Path: Any combination of Point of 

Receipt (POR) and Point of Delivery (POD) 

for which Available Transfer Capability 

(ATC) is calculated; and any Posted Path.95

Available Flowgate Capability (AFC): A 

measure of the flow capability remaining on 

a Flowgate for further commercial activity 

over and above already committed uses. It is 

defined as Total Flowgate Capability (TFC) 

less Existing Transmission Commitments 

(ETC), less a Capacity Benefit Margin (CBM), 

less a Transmission Reliability Margin 

(TRM), plus Postbacks, and plus 

counterflows. 

Available Transfer Capability (ATC): A 

measure of the transfer capability remaining 

in the physical transmission network for 

further commercial activity over and above 

already committed uses. It is defined as Total 

Transfer Capability (TTC) less Existing 

Transmission Commitments (ETC) (including 

retail customer service), less a Capacity 

Benefit Margin (CBM), less a Transmission 

Reliability Margin (TRM), plus Postbacks, 

plus counterflows. 

Available Transfer Capability 

Implementation Document (ATCID): A 

document that describes the implementation 

of a methodology for calculating Available 

Transfer Capability (ATC) or Available 

Flowgate Capability (AFC), and provides 

information related to a Transmission Service 

Provider’s calculation of ATC or AFC. 

Block Dispatch: A set of dispatch rules 

such that given a specific amount of load to 

serve, an approximate generation dispatch 

can be determined. To accomplish this, the 

capacity of a given generator is segmented 

into loadable ‘‘blocks,’’ each of which is 

grouped and ordered relative to other blocks 

(based on characteristics including, but not 

limited to, efficiency, run of river or fuel 

supply considerations, and/or ‘‘must-run’’ 

status). 

Business Practices: Those business rules 

contained in the Transmission Service 

Provider’s applicable tariff, rules, or 

procedures; associated Regional Reliability 

Organization or Regional Entity business 

practices; or North American Energy 

Standards Board (NAESB) Business Practices. 

Capacity Benefit Margin Implementation 

Document (CBMID): A document that 

describes the implementation of a Capacity 

Benefit Margin methodology. 

Dispatch Order: A set of dispatch rules 

such that given a specific amount of load to 

serve, an approximate generation dispatch 

can be determined. To accomplish this, each 

generator is ranked by priority. 

Existing Transmission Commitments 

(ETC): Committed uses of a Transmission 

Service Provider’s Transmission system 

considered when determining Available 

Transfer Capability (ATC) or Available 

Flowgate Capability (AFC). 

Flowgate: 

(1) A portion of the Transmission system 

through which the Interchange Distribution 

Calculator calculates the power flow from 

Interchange Transactions. 

(2) A mathematical construct, comprised of 

one or more monitored transmission 

Facilities and optionally one or more 

contingency Facilities, used to analyze the 

impact of power flows upon the Bulk Electric 

System. 

Flowgate Methodology: The Flowgate 

methodology is characterized by 

identification of key Facilities as Flowgates. 

Total Flowgate Capabilities (TFC) are 

determined based on Facility Ratings and 

voltage and stability limits. The impacts of 

Existing Transmission Commitments (ETCs) 

are determined by simulation. The impacts of 

ETC, Capacity Benefit Margin (CBM) and 

Transmission Reliability Margin (TRM) are 

subtracted from the TFC, and Postbacks and 

counterflows are added, to determine the 

Available Flowgate Capability (AFC) value 

for that Flowgate. AFCs can be used to 

determine Available Transfer Capability 

(ATC). 

Generation Capability Import Requirement 

(GCIR): The amount of generation capability 

from external sources identified by a LoadServing Entity (LSE) or Resource Planner 

(RP) to meet its generation reliability or 

resource adequacy requirements as an 

alternative to internal resources. 

Outage Transfer Distribution Factor 

(OTDF): In the post-contingency 

configuration of a system under study, the 

electric Power Transfer Distribution Factor 

(PTDF) with one or more system Facilities 

removed from service (outaged). 

Participation Factors: A set of dispatch 

rules such that given a specific amount of 

load to serve, an approximate generation 

dispatch can be determined. To accomplish 

this, generators are assigned a percentage that 

they will contribute to serve load. 

Planning Coordinator: See Planning 

Authority. 

Postback: Positive adjustments to Available 

Transfer Capability (ATC) or Available 

Flowgate Capability (AFC) as defined in 

Business Practices. Such Business Practices 

may include processing of redirects and 

unscheduled service. 

Power Transfer Distribution Factor (PTDF): 

In the pre-contingency configuration of a 

system under study, a measure of the 

responsiveness or change in electrical 

loadings on transmission system Facilities 

due to a change in electric power transfer 

from one area to another, expressed in 

percent (up to 100%) of the change in power 

transfer. 

Rated System Path Methodology: The 

Rated System Path Methodology is 

characterized by an initial Total Transfer 

Capability (TTC), determined via simulation. 

Capacity Benefit Margin (CBM), 

Transmission Reliability Margin (TRM), and 

Existing Transmission Commitments (ETC) 

are subtracted from TTC, and Postbacks and 

counterflows are added as applicable, to 

derive Available Transfer Capability (ATC). 

Under the Rated System Path Methodology, 

TTC results are generally reported as specific 

transmission path capabilities. 

Total Flowgate Capability (TFC): The 

maximum flow capability on a Flowgate, is 

not to exceed its thermal rating, or in the case 

of a flowgate used to represent a specific 

operating constraint (such as a voltage or 

stability limit), is not to exceed the associated 

System Operating Limit. 

Transmission Operator Area: The 

collection of Transmission assets over which 

the Transmission Operator is responsible for 

operating. 

Transmission Reliability Margin 

Implementation Document (TRMID): A 

document that describes the implementation 

of a Transmission Reliability Margin (TRM) 

methodology, and provides information 

related to a Transmission Operator’s 

calculation of TRM. 

2. Commission Proposal 

141. The Commission proposes to 

approve the addition of these terms to 

the NERC Glossary with minor 

modification. The Commission believes 

that the definition of Postback is not 

fully determinative. NERC should be 

able to define this term without 

reference to Business Practices, another 

defined term. The Commission therefore 

proposes to direct NERC to modify the 

definition of Postback. 

142. The definition of Business 

Practices includes a reference to the 

‘‘regional reliability organization.’’ In 

Order No. 693, the Commission directed 

NERC to eliminate references to regional 

reliability organizations as responsible 

entities in the Reliability Standards 


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12768 Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 

96Order No. 693, FERC Stats. & Regs.¶ 31,242 at 

P 157. 

97 16 U.S.C. 824o. 

98 44 U.S.C. 3507(d). 

99 5 CFR 1320.11. 

100These burden estimates apply only to this 

NOPR and do not reflect upon all of FERC–516 or 

FERC–717. 

101Regulations Implementing the National 

Environmental Policy Act, Order No. 486, 52 FR 

47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 

(1987). 

102 18 CFR 380.4(a)(5). 

103 5 U.S.C. 601–612. 

104The definition of ‘‘small entity’’ under the 

Regulatory Flexibility Act refers to the definition 

provided in the Small Business Act, 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 

(2000). 

because such entities are not users, 

owners or operators of the Bulk-Power 

System.96 Accordingly, the Commission 

proposes to direct NERC to remove from 

the proposed definition of Business 

Practices, the reference to regional 

reliability organizations and replace it 

with the term Regional Entity. However, 

Regional Entity is not currently defined 

in the NERC Glossary. The Commission 

therefore proposes to direct NERC to 

develop a definition of Regional Entity 

consistent with section 215(a) of the 

FPA 97 and 18 CFR 39.1 (2008), to be 

included in the NERC Glossary. 

IV. Information Collection Statement 

143. 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 1995.98

OMB’s regulations require OMB to 

approve certain information collection 

requirements imposed by agency rule.99

144. Comments are solicited on the 

need for this information, whether the 

information will have practical utility, 

ways to enhance the quality, utility, and 

clarity of the information to be 

collected, and any suggested methods 

for minimizing respondents’ burden, 

including the use of automated 

information techniques. 

Burden Estimate: The public reporting 

and records retention burdens for the 

proposed reporting requirements and 

the records retention requirement are as 

follows.100

Data collection Number of 

respondents 

Number of 

responses 

Hours per 

response 

Total annual 

hours 

Mandatory data exchanges ............................................................................. 137 1 80 10,960 

Explanation of change of ATC values ............................................................. 137 1 100 13,700 

Recordkeeping ................................................................................................. 137 1 30 3,480 

Total Annual Hours for Collection: 

Reporting + recordkeeping hours = 

3,480 + 24,660 = 28,140 hours. 

Cost to Comply: 

Reporting = $2,811,240 

24,660 hours @ $114 an hour (average 

cost of attorney ($200 per hour), 

consultant ($150), technical ($80), 

and administrative support ($25)) 

Recordkeeping = $185,875 (same as 

below) 

Labor (file/record clerk @ $17 an 

hour) 3,480 hours @ $17/hour = 

$59,150 

Storage 137 respondents @ 8,000 sq. 

ft. × $925 (off site storage) = 

$126,725 

Total costs = $2,997,115 

Labor $ ($2,811,240+ $59,150) + 

Recordkeeping Storage Costs 

($126,725) 

OMB’s regulations require it to 

approve certain information collection 

requirements imposed by an agency 

rule. The Commission is submitting 

notification of this proposed rule to 

OMB. If the proposed requirements are 

adopted they will be mandatory 

requirements. 

Title: Mandatory Reliability Standards 

for the Calculation of Available Transfer 

Capability, Capacity Benefit Margins, 

Transmission Reliability Margins, Total 

Transfer Capability, and Existing 

Transmission Commitments and 

Mandatory Reliability Standards for the 

Bulk-Power System. 

Action: Proposed Collections. 

OMB Control Nos. [to be determined]. 

Respondents: Business or other for 

profit. 

Frequency of responses: On occasion. 

Necessity of the Information: 

145. Internal Review: The 

Commission has reviewed the proposed 

reliability standards and made a 

determination that these requirements 

are necessary to implement section 215 

of the Energy Policy Act of 2005. These 

requirements conform to the 

Commission’s plan for efficient 

information collection, communication 

and management within the energy 

industry. The Commission has to assure 

itself, by means of internal review, that 

there is specific, objective support for 

the burden estimates associated with the 

information requirements. 

146. Interested persons may obtain 

information on the reporting 

requirements by contacting the 

following: Federal Energy Regulatory 

Commission, 888 First Street, NE. 

Washington, DC 20426 [Attention: 

Michael Miller, Office of the Executive 

Director, Phone: (202) 502–8415, fax: 

(202) 273–0873, e-mail: 

michael.miller@ferc.gov]. 

147. For submitting comments 

concerning the collection(s) of 

information and the associated burden 

estimate(s), please send your comments 

to the contact listed above and to the 

Office of Information and Regulatory 

Affairs, Office of Information and 

Regulatory Affairs, Washington, DC 

20503 [Attention: Desk Officer for the 

Federal Energy Regulatory Commission, 

phone (202) 395–4650, fax: (202) 395– 

7285, e-mail: 

oira_submission@omb.eop.gov]. 

V. Environmental Analysis 

148. 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.101 The actions proposed 

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.102

VI. Regulatory Flexibility Act 

Certification 

149. The Regulatory Flexibility Act of 

1980 (RFA) 103 generally requires a 

description and analysis of final rules 

that will have significant economic 

impact on a substantial number of small 

entities. The MOD Reliability Standards 

apply to transmission service providers 

and transmission operators, most of 

which do not fall within the definition 

of small entities.104

150. As indicated above, 

approximately 137 entities will be 

responsible for compliance with the 

three new Reliability Standards. Of 

these only six, or less than five percent, 

have output of four million MWh or less 


PWALKER on PROD1PC71 with PROPOSALS
Federal Register / Vol. 74, No. 56 / Wednesday, March 25, 2009 / Proposed Rules 12769 

105 Id. 

106The Regulatory Flexibility Act defines a 

‘‘small entity’’ as ‘‘one which is independently 

owned and operated and which is not dominant in 

its field of operation.’’ See 5 U.S.C. 601(3) and 

601(6); 15 U.S.C. 632(a)(1). In Mid-Tex Elec. Coop. 

v. FERC, 773 F.2d 327, 340–43 (DC Cir. 1985), the 

court accepted the Commission’s conclusion that, 

since virtually all of the public utilities that it 

regulates do not fall within the meaning of the term 

small entities as defined in the Regulatory 

Flexibility Act, the Commission did not need to 

prepare a regulatory flexibility analysis in 

connection with its proposed rule governing the 

allocation of costs for construction work in progress 

(CWIP). The CWIP rules applied to all public 

utilities. The revised pro forma OATT will apply 

only to those public utilities that own, control or 

operate interstate transmission facilities. These 

entities are a subset of the group of public utilities 

found not to require preparation of a regulatory 

flexibility analysis for the CWIP rule. 

per year.105 The Commission does not 

consider this a substantial number.106

Based on this understanding, the 

Commission certifies that this rule will 

not have a significant economic impact 

on a substantial number of small 

entities. Accordingly, no regulatory 

flexibility analysis is required. 

VII. Comment Procedures 

151. The Commission invites 

interested persons to submit comments 

on the matters and issues proposed in 

this notice to be adopted, including any 

related matters or alternative proposals 

that commenters may wish to discuss. 

Comments are due May 26, 2009. 

Comments must refer to Docket Nos. 

RM08–19–000, RM08–19–001, RM09– 

5–000 and RM06–16–005, and must 

include the commenter’s name, the 

organization they represent, if 

applicable, and their address in their 

comments. 

152. 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. 

153. Commenters that are not able to 

file comments electronically must send 

an original and 14 copies of their 

comments to: Federal Energy Regulatory 

Commission, Secretary of the 

Commission, 888 First Street NE., 

Washington, DC 20426. 

154. 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 

155. 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. 

156. 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. 

157. 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. 

Kimberly D. Bose, 

Secretary. 

[FR Doc. E9–6505 Filed 3–24–09; 8:45 am] 

BILLING CODE 6717–01–P 

DEPARTMENT OF HOMELAND 

SECURITY 

Coast Guard 

33 CFR Part 100 

[Docket No. USCG–2009–0106] 

RIN 1625–AA08 

Special Local Regulation for Marine 

Events; Temporary Change of Dates 

for Recurring Marine Events in the 

Fifth Coast Guard District 

AGENCY: Coast Guard, DHS. 

ACTION: Notice of proposed rulemaking. 

SUMMARY: The Coast Guard proposes to 

temporarily change the enforcement 

period of special local regulations for 

recurring marine events in the Fifth 

Coast Guard District. These regulations 

apply to only five recurring marine 

events that conduct on water activities 

such as power boat races, swimming 

competitions, and harbor celebrations. 

Special local regulations are necessary 

to provide for the safety of life on 

navigable waters during the event. This 

action is intended to restrict vessel 

traffic in portions of the Chester River, 

MD; Rappahannock River, VA; Elizabeth 

River, Southern Branch, VA; North 

Atlantic Ocean, Ocean City, MD; and 

Pasquotank River during each event. 

DATES: Comments and related material 

must either be submitted to our online 

docket via http://www.regulations.gov 

on or before April 24, 2009 or reach the 

Docket Management Facility by that 

date. 

ADDRESSES: You may submit comments 

identified by docket number USCG– 

2009–0106 using any one of the 

following methods: 

(1) Federal eRulemaking Portal: 

http://www.regulations.gov. 

(2) Fax: 202–493–2251. 

(3) Mail: Docket Management Facility 

(M–30), U.S. Department of 

Transportation, West Building Ground 

Floor, Room W12–140, 1200 New Jersey 

Avenue, SE., Washington, DC 20590– 

0001. 

(4) Hand delivery: Same as mail 

address above, between 9 a.m. and 5 

p.m., Monday through Friday, except 

Federal holidays. The telephone number 

is 202–366–9329. 

To avoid duplication, please use only 

one of these methods. For instructions 

on submitting comments, see the 

‘‘Public Participation and Request for 

Comments’’ portion of the 

SUPPLEMENTARY INFORMATION section 

below. 

FOR FURTHER INFORMATION CONTACT: If 

you have questions on this proposed 

rule, call Dennis Sens, Project Manager, 

Fifth Coast Guard District, Prevention 

Division, at 757–398–6204 or e-mail at 

Dennis.M.Sens@uscg.mil. If you have 

questions on viewing or submitting 

material to the docket, call Renee V. 

Wright, Program Manager, Docket 

Operations, telephone 202–366–9826. 

SUPPLEMENTARY INFORMATION: 

Public Participation and Request for 

Comments 

We encourage you to participate in 

this rulemaking by submitting 

comments and related materials. All 

comments received will be posted, 

without change, to http:// 

www.regulations.gov and will include 

any personal information you have 

provided. 

Submitting Comments 

If you submit a comment, please 

include the docket number for this 

rulemaking (USCG–2009–0106), 


PWALKER on PROD1PC71 with PROPOSALS