129 FERC ¶ 61,155 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 40 

[Docket No. RM08-19-000, et al.; Order No. 729] 

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 November 24, 2009) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Final Rule. 

SUMMARY: Pursuant to section 215 of the Federal Power Act, the Commission 

approves 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 approved 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. Pursuant to section 215(d)(5) of the FPA and section 

39.5(f) of our regulations, the Commission also directs the ERO to develop certain 

modifications to the MOD Reliability Standards. Finally, the Commission directs NERC 

to retire the existing MOD Reliability Standards replaced by the versions proposed here. 

 
Docket No. RM08-19-000, et al. - 2 - 

EFFECTIVE DATE: This rule will become effective [insert date that is 60 days after 

publication in the FEDERAL REGISTER]

FOR FURTHER INFORMATION CONTACT: 

Jonathan First (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-8529 

Cory Lankford (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-6711 

Christopher Young (Technical Information)

Office of Electric Reliability 

Federal Energy Regulatory Commission 

888 First Street, NE 

Washington, DC 20426 

(202) 502-6403 

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

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 

Docket Nos. RM08-19-000 

RM08-19-001 

RM09-5-000 

RM06-16-005 

ORDER NO. 729 

(Issued November 24, 2009) 

TABLE OF CONTENTS

 Paragraph Numbers

I. Background...........................................................................................................................5.

A. Order Nos. 888 and 889 ...................................................................................................5.

B. Order Nos. 890 and 693 ...................................................................................................9.

II. MOD Reliability Standards...............................................................................................13.

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.

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. Approval, Implementation and Audit of the MOD Reliability Standards .......................75.

1. Approval of the MOD Reliability Standards................................................................83.

2. Implementation Timeline .............................................................................................92.

3. Implementation Document Audits................................................................................96.

a. Authority to Direct Audits........................................................................................96.
Docket No. RM08-19-000, et al. ii 

b. Performance of Audits .............................................................................................112.

c. Additional Requirements to Prevent Undue Discrimination....................................132.

B. Modification of the Reliability Standards ........................................................................137.

1. MOD-001-1 ..................................................................................................................137.

a. Availability of the Implementation Documents .......................................................137.

b. Dispatch Model Assumptions ..................................................................................152.

c. Treatment of Network Resource Designations ........................................................165.

d. Updating Available Transfer Capability and Available Flowgate Capability 

Values............................................................................................................................176.

e. MOD-001-1, Consistent Treatment of Assumptions ...............................................180.

f. MOD-001-1, Requirement R2 ..................................................................................185.

g. MOD-001-1, Requirement R3 .................................................................................193.

h. MOD-001-1, Requirements R6 and R7 ...................................................................196.

i. MOD-001-1, Requirement R9 ..................................................................................202.

j. MOD-001-1, Counterflows.......................................................................................207.

2. MOD-004-1, Capacity Benefit Margin ........................................................................211.

3. MOD-008-1, Transfer Reliability Margin....................................................................223.

4. MOD-028-1, Area Interchange Methodology..............................................................226.

a. General .....................................................................................................................227.

b. MOD-028-1, Requirement R2 .................................................................................229.

c. MOD-028-1, Requirement R5..................................................................................232.

d. MOD-028-1, Requirement R6 .................................................................................235.

5. MOD-029-1, Rated System Path Methodology ...........................................................238.

a. Sub-Requirement R2.7 .............................................................................................238.

b. Counterschedules .....................................................................................................245.

6. MOD-030-2, Flowgate Methodology...........................................................................247.

a. MOD-030-2 Requirements R2.4 and R2.5...............................................................248.

b. MOD-030-2 Requirements R3 and R10 ..................................................................251.

c. MOD-030-2 Existing Transmission Commitments, Requirement R6.....................254.

d. MOD-030-2 Power Transfer and Outage Transfer Distribution Factors.................260.

e. MOD-030-2 Treatment of Adjacent Systems ..........................................................263.

f. MOD-030-2 Effective Date ......................................................................................267.

C. Violation Risk Factors and Violation Severity Levels.....................................................270.

D. Disposition of Other Reliability Standards ......................................................................275.

1. MOD-010-1 through MOD-025-1................................................................................275.

2. Reliability Standards to be Retired or Withdrawn .......................................................277.

E. Applicability .....................................................................................................................292.

F. Definitions.........................................................................................................................299.

IV. Information Collection Statement ...................................................................................307.

V. Environmental Analysis .....................................................................................................313.
Docket No. RM08-19-000, et al. iii 

VI. Regulatory Flexibility Act ................................................................................................314.

VII. Document Availability.....................................................................................................317.

VIII. Effective Date and Congressional Notification ...........................................................320.
 

129 FERC ¶ 61,155 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 and Philip D. Moeller. 

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 

Docket Nos. RM08-19-000 

RM08-19-001 

RM09-5-000 

RM06-16-005 

ORDER NO. 729 

FINAL RULE 

(Issued November 24, 2009) 

1. Pursuant to section 215 of the Federal Power Act (FPA),1

 the Federal Energy 

Regulatory Commission (Commission) approves, and directs modifications to, six 

Modeling, Data and Analysis (MOD) Reliability Standards submitted to the Commission 

by the North American Electric Reliability Corporation (NERC), the Commissioncertified Electric Reliability Organization (ERO) for the United States.2

 The approved 

Reliability Standards pertain to methodologies for the consistent and transparent 

1

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

2

 North American Electric Reliability Corp., 116 FERC ¶ 61,062 (ERO 

Certification Order), order on reh’g & compliance, 117 FERC ¶ 61,126 (2006) (ERO 

Rehearing Order), aff’d, Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009). 
Docket No. RM08-19-000, et al. - 2 - 

ards. 

 

calculation of available transfer capability or available flowgate capability. Pursuant to 

section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission 

directs the ERO to develop certain modifications to the MOD Reliability Standards.3

 

The Commission also directs NERC to retire the existing MOD Reliability Standards 

replaced by the versions approved here. The retirement of these Reliability Standards

will be effective upon the effective date of the proposed MOD Reliability Stand

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.4

 In Order No. 693, the 

Commission reiterated its concerns expressed in Order No. 890 and stated that available 

transfer capability raises both comparability and reliability issues, and that it would be 

irresponsible to require consistency in the available transfer capability calculation without 

3

 16 U.S.C. 824o(d)(5). 

4

 Preventing 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, 123 FERC ¶ 61,299 (2008), order on reh’g, 

Order No. 890-C, 126 FERC ¶ 61,228 (2009). 
Docket No. RM08-19-000, et al. - 3 - 

 

considering the reliability impact of those decisions.5

 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 approved 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 approves the Reliability Standards filed by NERC in this 

proceeding as just, reasonable, not unduly discriminatory or preferential, and in the 

public interest.6

 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 approved Reliability Standards will enhance 

transparency in the calculation of available transfer capability, requiring transmission 

5

 Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, 

72 FR 16416 (Apr. 4, 2007), FERC Stats. & Regs. ¶ 31,242, at P 1022 (2007), order on 

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

6

 16 U.S.C. 824o(d)(2). 
Docket No. RM08-19-000, et al. - 4 - 

 

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.7

 The approved 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, which in turn will allow the Commission and 

others to ensure consistency in their application. By promoting consistency, 

standardization and transparency, these Reliability Standards enhance the reliability of 

the Bulk-Power System. 

4. On March 19, 2009, the Commission issued its Notice of Proposed Rulemaking 

(NOPR) proposing to approve the six MOD Reliability Standards.8

 The Commission 

7

 Reliability entities include: transmission service providers, planning 

coordinators, reliability coordinators, and transmission operators as those entities are 

defined in the NERC Glossary of Terms Used in Reliability Standards (Glossary), 

(Effective February 12, 2008), available at: 

http://www.nerc.com/docs/standards/rs/Glossary_12Feb08.pdf. Standards adopted by the 

North American Energy Standards Board (NAESB) govern disclosure of this information 

to other entities. The Commission accepts the associated NAESB business practices in a 

Final Rule issued concurrently in Docket No. RM05-5-013. See Standards for Business 

Practices and Communication Protocols for Public Utilities, No. 676-E, 129 FERC 

¶ 61,162 (2009).

8

 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 

(continued...) 
Docket No. RM08-19-000, et al. - 5 - 

also proposed to direct NERC to retire the currently effective MOD Reliability Standards 

along with one FAC Reliability Standard. The Commission proposed that NERC retain 

another FAC Reliability Standard, FAC-012-1, and proposed that the ERO develop 

modifications to conform with the MOD Reliability Standards approved herein. The 

Commission also proposed to direct NERC to expand the disclosure provisions and 

conduct audits of certain implementation documents associated with the Reliability 

Standards to be approved herein. In response to the NOPR, comments were filed by 37 

interested parties. In the discussion below, we address the issues raised by these 

comments. Appendix A to this Final Rule lists the entities that filed comments on the 

NOPR. 

I. Background

A. Order Nos. 888 and 889

5. In April 1996, as part of its statutory obligation under sections 205 and 206 of the 

FPA9

 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.10 In that order, the Commission required all public utilities 

 

Standards for the Bulk-Power System, 74 FR 12747 (March 25, 2009), FERC Stats. & 

Regs. ¶ 32,641 (2009) (“NOPR”). 

9

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

10 Promoting 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. & 

(continued...) 
Docket No. RM08-19-000, et al. - 6 - 

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 non-discriminatory 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.11 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).12 After their OATTs 

became effective, public utilities were allowed to file, pursuant to section 205 of the FPA, 

 

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 

(D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002). 

11 This 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. 

12 See 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). 
Docket No. RM08-19-000, et al. - 7 - 

deviations that were consistent with or superior to the pro forma OATT’s terms and 

conditions. 

6. The same day it issued Order No. 888, the Commission issued a companion order, 

Order No. 889,13 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. 

7. 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 before-the-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 

 13 Open 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). 
Docket No. RM08-19-000, et al. - 8 - 

 

availability.”14 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.15 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.16 The Commission noted that the 

requirement that transmission service providers make available for 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.”17

8. 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.18 As a result, a variety of methodologies to calculate 

14 Order No. 889, FERC Stats. & Regs. ¶ 31,035 at 31,749. 

15 Id. at 31,750. 

16 Id. 

17 Id. 

18 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,749 n.610. 
Docket No. RM08-19-000, et al. - 9 - 

available transfer capability 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

9. Section 215 of the FPA requires a Commission-certified ERO to develop 

mandatory and enforceable Reliability Standards that provide for the reliable operation of 

the Bulk-Power System, 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. 

10. On February 16, 2007, the Commission issued Order No. 890, which addressed 

and remedied opportunities for undue discrimination under the pro forma OATT adopted 
Docket No. RM08-19-000, et al. - 10 - 

 

in Order No. 888. Among other things, the Commission required industry-wide 

consistency and transparency of all components of available transfer capability 

calculation and certain definitions, data and modeling assumptions. The Commission 

concluded that the lack of industry-wide criteria 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 found 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.19 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. 

11. The Commission stated in Order No. 890 that the available transfer capabilityrelated 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 that there be just one computational 

process for calculating available transfer capability because, among other things, it found 

19 FPA section 215(d)(5). 16 U.S.C. 824o(d)(5). 
Docket No. RM08-19-000, et al. - 11 - 

 

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.20 The Commission found that, if all of the available transfer capability 

components, certain data inputs and certain assumptions are consistent, the three 

available transfer capability calculation methodologies would produce predictable and 

sufficiently accurate, consistent, equivalent and replicable results.21

12. On March 16, 2007, the Commission issued Order No. 693, approving 83 of the 

107 Reliability Standards filed by NERC in April 2006.22 Of the 83 approved Reliability 

Standards, the Commission approved ten MOD Reliability Standards.23 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. 890.24 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 

20 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 1029. 

21 Id. P 1030. 

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

23 Id. P 1010. 

24 Id. 
Docket No. RM08-19-000, et al. - 12 - 

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.25 The Commission directed public utilities, working through the 

NERC Reliability Standards and North American Energy Standards Board (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.26 

II. MOD Reliability Standards

13. In response to the requirements of Order No. 890 and related directives of Order 

No. 693,27 on August 29, 2008, NERC submitted for Commission approval five MOD 

Reliability Standards: MOD-001-1 – Available Transmission System Capability, 

 25 Id. P 1029-30; see also Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 207. 

26 Order 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. 

27 The 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 

No. 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. 
Docket No. RM08-19-000, et al. - 13 - 

 

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.28 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-030-1.29 

14. 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. 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. 

28 NERC 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.” 

29 The MOD Reliability Standards are not codified in the CFR and are not attached 

to the Final Rule. They are, however, available on the Commission’s eLibrary document 

retrieval system and on the ERO’s website, http://www.nerc.com. 
Docket No. RM08-19-000, et al. - 14 - 

15. NERC contends that the Reliability Standards will have no undue negative effect 

on competition, nor will they unreasonably restrict available transfer capability on the 

Bulk-Power 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 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 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. 

16. 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 
Docket No. RM08-19-000, et al. - 15 - 

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. 

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 MOD 

Reliability Standards and related NAESB business-practice standards.30 NERC states 

that the focus of the MOD Reliability Standards is to address only the reliability aspects 

of available transfer capability and available flowgate capability, not commercial aspects, 

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 

 30 As noted above, the Commission addresses the NAESB business practices in a 

Final Rule issued concurrently in Docket No. RM05-5-013. See Standards for Business 

Practices and Communication Protocols for Public Utilities, Order No. 676-E, 129 FERC 

¶ 61,162 (2009). 
Docket No. RM08-19-000, et al. - 16 - 

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. 

They intend to 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 violations of system operating limits and 

interconnection reliability operating limits. 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. NERC contends that such selection ensures that the determination of 
Docket No. RM08-19-000, et al. - 17 - 

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 for either planning for 

native load or use 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. MOD-001-1 includes nine requirements, which apply 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 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 
Docket No. RM08-19-000, et al. - 18 - 

 

monthly) for the facilities in its area. As stated above, the three methodologies are: the 

area interchange methodology, the rated system path methodology, and the flowgate 

methodology. 

23. Several requirements within this MOD-001-1 address 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.31 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 

31 See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 237; Order No. 693, 

FERC Stats. & Regs. ¶ 31,242 at P 1051. 
Docket No. RM08-19-000, et al. - 19 - 

 

available transfer capability and available flowgate capability calculations be consistent 

with those used for planning the expansion or operation of the Bulk-Power System to the 

maximum extent possible.32 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.33

24. MOD-001-1 also includes 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.34 Requirement R5 requires the transmission service provider 

32 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1057; see also Order 

No. 890, FERC Stats. & Regs. ¶ 31,241 at P 292. 

33 See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 301; Order No. 693, 

FERC Stats. & Regs. ¶ 31,242 at P 1057. 

34 These include: each planning coordinator, reliability coordinator, and 

transmission operator associated with the transmission service provider’s area; and each 

(continued...) 
Docket No. RM08-19-000, et al. - 20 - 

 

to make the available transfer capability implementation document available to those 

same reliability entities.35 Finally, 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. 

planning coordinator, reliability coordinator, and transmission service provider adjacent 

to the transmission service provider’s area. 

35 Although 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. 
Docket No. RM08-19-000, et al. - 21 - 

C. Capacity Benefit Margin Methodology, MOD-004-1 

26. The Capacity Benefit Margin Methodology Reliability Standard (MOD-004-1) 

provides for the calculation of capacity benefit margin. NERC defines capacity benefit 

margin as the amount of firm transmission capability set aside 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.36 The purpose of this 

Reliability Standard is to promote the consistent and reliable calculation, verification, 

setting aside, and use of capacity benefit margin to support analysis and system 

operations. NERC states that setting aside 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. Reliability Standard MOD-004-1 applies 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 

 36 See NERC Glossary. 
Docket No. RM08-19-000, et al. - 22 - 

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 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 

load-serving 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 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, 
Docket No. RM08-19-000, et al. - 23 - 

 

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 to 

determine the need for transmission capacity to be set aside as capacity benefit margin for 

imports into a balancing authority by using one or more of the following to determine the 

generation capability import requirement:37 loss of load expectation studies, loss of load 

probability studies, deterministic risk-analysis 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 

37 NERC 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. 
Docket No. RM08-19-000, et al. - 24 - 

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 all load-serving entities and resource planners that 

determined they had a need for capacity benefit margin of the amount, or the amount 
Docket No. RM08-19-000, et al. - 25 - 

 

planned, of capacity benefit margin set aside, within 31 calendar days after the 

establishment of capacity benefit margin.

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.38

35. When reviewing an arranged interchange service request using capacity benefit 

margin, Requirement R11 requires all balancing authorities and transmission service 

providers to waive, within the bounds of reliable operation, any real-time timing and 

ramping requirements.

38 Under Reliability Standard EOP-002-2 Reliability Coordinators initiate an 

energy emergency alert when a balancing authority within its control area experiences a 

potential or actual energy emergency. NERC has established three levels of energy 

emergency alerts (one through three) to clarify the severity of the potential or actual 

energy emergency. 
Docket No. RM08-19-000, et al. - 26 - 

 

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”39 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 MOD-004-1 complies with the requirements of Order No. 890 

and related directives of Order No. 693 because it sets criteria 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.40 NERC supports this approach 

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 and resource planners to perform specific studies to determine their 

need for capacity benefit margin. By specifying the types of studies load-serving entities 

39 Energy deficient entities are defined by NERC in the Capacity and Energy 

Emergencies Reliability Standard. See EOP-002-2, Attachment 1. 

40 Citing Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1078; see also Order 

No. 890, FERC Stats. & Regs. ¶ 31,241 at P 257. 
Docket No. RM08-19-000, et al. - 27 - 

 

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.

41 In response to the Commission’s transparency requirement,42 NERC states 

that Requirement R9 ensures that capacity benefit margin studies are made available to 

the appropriate reliability entities for their review and 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.43 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-001-1.44 NERC states that Requirements R10, R11 and R12 specify the 

41 Citing Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1105. 

42 Citing id. P 1077. 

43 Citing 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. 

44 Citing id. P 257; Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1082. 
Docket No. RM08-19-000, et al. - 28 - 

 

manner in which capacity benefit margin is to be used.45 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 values be verifiable,46

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 amounts of capacity benefit margin 

requested by transmission service provider 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. 

45 Citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 256-7. 

46 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1077. 
Docket No. RM08-19-000, et al. - 29 - 

40. In response to the Commission’s call for clarity in the process for requesting 

capacity benefit margin,47 NERC states that Requirement R1.1 requires the transmission 

service provider to 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. The Transmission Reliability Margin Methodology Reliability Standard 

(MOD-008-1) provides for the calculation of transmission reliability margin. 

 47 Id. P 1081. 
Docket No. RM08-19-000, et al. - 30 - 

 

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.48 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. MOD-008-1 describes the reliability aspects of 

determining and maintaining a transmission reliability margin and the components of 

uncertainty that may be considered when making that calculation. 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. 

42. Reliability Standard MOD-008-1 applies 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. To improve the transparency of transmission reliability margin calculations, the 

Reliability Standard imposes five requirements on transmission service providers electing 

48 See NERC Glossary, available at: 

http://www.nerc.com/docs/standards/rs/Glossary_2009April20.pdf. 
Docket No. RM08-19-000, et al. - 31 - 

 

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 topology49 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. 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. 

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 

49 This 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. 
Docket No. RM08-19-000, et al. - 32 - 

 

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.50 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 available documents supporting the 

transmission reliability margin determination 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,51 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 or reliability coordinator. 

50 NERC Filing at 32 (citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at 

P 273). 

51 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1126. 
Docket No. RM08-19-000, et al. - 33 - 

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,52 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 be reduced or 

eliminated as one approaches real time, the non-firm equations allow for the partial 

release of transmission reliability margin. 

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 

 52 See Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 273. 
Docket No. RM08-19-000, et al. - 34 - 

 

and sufficiently accurate, consistent, equivalent and replicable results.53 Consistent with 

Order No. 890, NERC developed 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,54 the 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 

53 Id. P 210. 

54 A 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. 
Docket No. RM08-19-000, et al. - 35 - 

Standards reduce the potential for seams discrepancies and improve the wide-area 

understanding of the Bulk-Power System on a forward-looking basis. NERC states that, 

by promoting consistency, standardization and transparency, they directly support and 

improve the reliability of the Bulk-Power 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 short-term use performed by entities 

using the area interchange methodology to support analysis and system operations. 

55. This Reliability Standard applies only to transmission operators and transmission 

service providers that elect to implement this particular methodology as part of their 
Docket No. RM08-19-000, et al. - 36 - 

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. The document must include 

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. The document must also 

include 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 
Docket No. RM08-19-000, et al. - 37 - 

next day time periods, as well as days two through 31 and for months two through 13.55 

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 it must communicate to the 

transmission service provider within the time frames specified in Requirement R7. 

60. Requirements R8 through R11 specify the formulas and provide descriptions of 

the variables to be used to calculate 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 

 55 This information includes: expected generation and transmission outages, 

additions, and retirements; load forecasts; and unit commitment and dispatch order. 
Docket No. RM08-19-000, et al. - 38 - 

 

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 short-term use performed by entities using the rated system path 

methodology to support analysis and system operations. 

63. This Reliability Standard applies 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 limit56 or the value determined in Requirement R2. The 

transmission operator must then provide a transmission service provider with the 

56 The NERC Glossary defines a system operating limit as the value (such as MW, 

MVar, Amperes, Frequency or Volts) that satisfies the most limiting of the prescribed 

operating criteria for a specified system configuration to ensure operation within 

acceptable reliability criteria. 
Docket No. RM08-19-000, et al. - 39 - 

appropriate total transfer capability values and study report within seven days of 

finalization of the study report to be prepared under 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 also provides 

detailed descriptions of the variables to be used. 

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 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 short-term use performed by entities 

using the flowgate methodology to support analysis and system operations. 
Docket No. RM08-19-000, et al. - 40 - 

67. This Reliability Standard applies 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, 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. 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 
Docket No. RM08-19-000, et al. - 41 - 

 

flowgate.57 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 non-firm 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. 

57 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 313. 
Docket No. RM08-19-000, et al. - 42 - 

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. 

F. Implementation Plan

72. NERC requests 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. 

NERC notes that Requirement R9 of the Available Transmission System Capability 

Reliability Standard (MOD-001-1) establishes the requirement for entities to develop 

certain information and the three methodology Reliability Standards rely on this 

information from neighboring reliability entities for use in the development of its 

available transfer capability and available flowgate capability values. Due to this reliance 

on the MOD-001-1 information, NERC concludes that none of the methodology 
Docket No. RM08-19-000, et al. - 43 - 

 

Reliability Standards can be effectively implemented unless and until MOD-001-1 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 requests 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.58 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 

58 In jurisdictions where regulatory approval is not required, the MOD-004-1 and 

MOD-008-1 will become effective on the first day of the first calendar quarter that is 

twelve months after the date of approval by the NERC Board of Trustees. 
Docket No. RM08-19-000, et al. - 44 - 

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

A. Approval, Implementation and Audit of the MOD Reliability 

Standards

NOPR Proposal

75. In the NOPR, the Commission proposed to approve the Reliability Standards filed 

by NERC in this proceeding as just, reasonable, not unduly discriminatory or preferential, 

and in the public interest.59 The Commission stated that these Reliability Standards 

represent a step forward in eliminating the broad discretion previously afforded 

transmission service providers in the calculation of available transfer capability. 

76. 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. Reliability Standards MOD-004-1 and 

MOD-008-1 provide for the calculation of capacity benefit margin and transmission 

 59 NOPR, FERC Stats. & Regs. ¶ 32,641 at P 75. 
Docket No. RM08-19-000, et al. - 45 - 

 

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.60

77. The Commission expressed concern in the NOPR that the proposed Reliability 

Standards could be implemented by a particular transmission service provider or 

transmission operator in a way that enables them to unduly discriminate in the provision 

of open access transmission service. The Commission observed that, 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.61 The Commission explained that these documents 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 

60 MOD-001-1, Requirement R3. 

61 NOPR, FERC Stats. & Regs. ¶ 32,641 at P 81. 
Docket No. RM08-19-000, et al. - 46 - 

 

provider in particular circumstances. As noted by the Commission, this discretion 

appears in the three available transfer capability methodologies (MOD-028-1, 

MOD-029-1, an 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). 

78. The Commission clarified in the NOPR that 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 Commission explained that the Reliability Standards need not be 

so specific that they address every unique system difference or differences in risk 

assumptions when modeling expected flows. Instead, each transmission service provider 

should retain some discretion to reflect unique system conditions or modeling 

assumptions in its available transmission capability methodology.62 The Commission 

stated that any such system conditions or modeling assumptions, however, must be made 

sufficiently transparent and be implemented consistently for all transmission customers. 

79. In order to ensure adequate transparency, the Commission proposed to direct the 

ERO to conduct a review of the additional parameters and assumptions included by each 

62 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 51. 
Docket No. RM08-19-000, et al. - 47 - 

 

transmission service provider in its available transfer capability, capacity benefit margin, 

and transmission reliability margin implementation documents. In its audit, NERC 

would identify any parameters and assumptions that 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 capability, capacity benefit margin, and transmission reliability margin. Upon 

review of NERC’s analysis, the Commission indicated that it may direct the ERO to 

develop a modification to MOD-001-1, MOD-004-1, and MOD-008-1 to address any 

lack of transparency. The Commission proposed to direct the ERO to complete this audit 

no later than 180 days after the effective date of the Reliability Standards. 

80. The Commission emphasized that it did not intend 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 

methodology, but rather in the consistent application of its components.63 The 

Commission stated that it acknowledged in Order No. 890 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 

63 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 208. 
Docket No. RM08-19-000, et al. - 48 - 

calculation methodologies being developed by NERC would produce predictable and 

sufficiently accurate, consistent, equivalent and replicable results.64

81. The Commission clarified in the NOPR that this does not mean that the results of 

available transfer capability calculations on either side of an interface must be identical in 

every instance. The Commission stated that 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, the 

Commission stated that unique system differences or differences in risk assumptions can 

lead to variations in available transfer capability values. 

82. The Commission also reiterated that available transfer capability reforms approved 

herein address interests related to the Commission’s open access goals and the reliable 

operation of the Bulk-Power System. 

1. Approval of the MOD Reliability Standards

Comments

83. Many commenters support the Commission’s proposed approval of the proposed 

MOD Reliability Standards.65 For example, FirstEnergy contends that the MOD 

Reliability Standards, as proposed, completely address the calculation of ATC and its 

 64 Id. P 210. 

65 APPA, Bonneville, Duke, EEI, EPSA, Entegra, FirstEnergy, Georgia, ISO/RTO 

Council, SMUD and NERC. 
Docket No. RM08-19-000, et al. - 49 - 

 

corresponding TTC values. Others agree that the Reliability Standards represent a step 

forward in eliminating the broad discretion previously afforded transmission service 

providers in the calculation of available transfer capability.66 In addition, several 

commenters state that the proposed MOD Reliability Standards will provide greater 

transparency and consistency in the calculation of available transfer capability, available 

flowgate capability, capacity benefit margins and transmission reliability margins within 

the transmission service industry.67 

84. NRU, Pacific Northwest, the Public Power Council and Snohomish agree with the 

Commission that the use of the proposed Reliability Standards, indeed the use of any one 

standard, may not produce identical results when applied to a different transmission 

system. They also agree that, even when 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 transmission capability values. 

They state that they agree with the Commission that this will occur and is an acceptable 

result. They contend that each transmission provider must retain sufficient discretion to 

make assumptions and represent its system in the calculation such that its system 

reliability is assured. 

66 APPA, Bonneville, and ISO/RTO Council. 

67 Bonneville, ISO/RTO Council, Joint Municipals, and SMUD. 
Docket No. RM08-19-000, et al. - 50 - 

85. To the extent that there are any outstanding issues not addressed in NERC’s filing, 

APPA, the Georgia Companies and the Joint Municipals contend that the Commission 

should allow industry to address such issues through the NERC Reliability Standards 

development process. The Joint Municipals state that, imperfect though it is, the 

Reliability Standards development process is unequalled in its ability to secure industry 

input, cooperation and often consensus in the development of industry-wide protocols. 

86. Midwest ISO states that it concurs that multiple available transfer capability 

methodologies should be permitted but disagrees that a different Reliability Standard 

should be developed for each methodology. Midwest ISO contends that notwithstanding 

the use of an umbrella Reliability Standards, imposing a separate standard for each 

methodology, and corresponding risks of non-compliance therewith, could create a 

deterrent to using the methodology that provides the greatest benefits to reliability, where 

that methodology has higher compliance risks. 

Commission Determination

87. The Commission adopts the NOPR proposal and approves the MOD Reliability 

Standards and related additions to the NERC Glossary, to be effective as proposed by 

NERC, as just, reasonable, not unduly discriminatory or preferential, and in the public 

interest. By promoting consistency, standardization and transparency, these Reliability 

Standards enhance the reliability of the Bulk-Power System. 

88. The MOD Reliability Standards also represent a step forward in eliminating the 

broad discretion previously afforded transmission service providers in the calculation of 
Docket No. RM08-19-000, et al. - 51 - 

 

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.68 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 

calculations in a way that discriminates against competitors. 

89. 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 the Commission’s 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 

68 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 68. 
Docket No. RM08-19-000, et al. - 52 - 

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. 

90. The Commission finds that Midwest ISO’s concerns regarding the structure of the 

Reliability Standards to be misplaced. NERC, working through its Reliability Standards 

development process, developed the six Reliability Standards approved herein. The 

Commission believes that each Reliability Standard adequately ensures the reliable 

operation of the Bulk-Power System and, thus, sees no basis for limiting which 

methodology is chosen to calculate available transfer or flowgate capability. We believe 

that Midwest ISO’s remaining concerns, including variation in relative compliance 

burdens or risks among the three methodologies, are best considered through NERC’s 

enforcement and compliance program. 

91. As discussed in greater detail later in the Final Rule, the Commission has concern 

regarding several of the substantive requirements of the proposed Reliability Standards. 

To address these concerns, pursuant to section 215(d)(5) of the FPA and section 39.5(f) 

of our regulations, the Commission directs the ERO to develop modifications to the 

Reliability Standards to address discrete issues involving: the availability of each 

transmission service provider’s implementation documents; the consistent treatment of 
Docket No. RM08-19-000, et al. - 53 - 

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; the treatment of network resource designations in the 

calculation of available transfer capability; and several other issues raised by 

commenters. 

2. Implementation Timeline

Comments

92. EEI contends that the implementation date is ambiguous. EEI states that the 

implementation timeline could be understood to mean that the effective date of the 

Reliability Standards is either on the first day of the first quarter occurring 365 days after 

approval of these Reliability Standards or on January 1 of the year following a full 

calendar year after approval. Accordingly, EEI asks the Commission to clarify the 

intended implementation timeline. 

93. Bonneville contends that a one-year implementation timeframe is unrealistic for 

certain portions of the proposed MOD Reliability Standards. Bonneville states that it has 

been preparing to comply with the flowgate methodology approach set forth in MOD030-2. Bonneville states that, to date, it has identified twelve adjacent transmission 

service providers from which it will likely need to request data to determine the impacts 

on Bonneville’s network flow based system of the existing network integration 

transmission service, point-to-point transmission service, and grandfathered 

commitments reserved on those providers’ systems as required by Requirements R6 and 
Docket No. RM08-19-000, et al. - 54 - 

R7 of MOD-030-2. Although Bonneville can request its adjacent transmission service 

providers to provide that data in aggregate form pursuant to Requirement R9 of 

MOD-001-1, Bonneville contends that, to obtain sufficiently detailed data, it will have to 

coordinate separate data exchange arrangements with each adjacent transmission service 

provider. Bonneville states that it is unlikely that it will be able to accomplish this, along 

with the necessary software changes, associated testing, and possible tariff filings that 

would be required to comply with the proposed Reliability Standard, within one year. 

Accordingly, Bonneville asks that the Commission establish a two-year implementation 

compliance timeframe or, in the alternative, allow entities to request extensions on a 

case-by-case basis. 

94. In contrast, EPSA contends that the Commission should advance the 

implementation schedule. EPSA states that NERC provided no support for why it will 

take a full year from Commission approval to implement MOD-001-1. EPSA contends 

that transmission service providers have long known that Order No. 890’s available 

transfer capability reform was coming. EPSA further contends that much of what is 

proposed in the MOD NOPR could be accomplished during the MOD NOPR’s 

development, if not before. EPSA questions whether the documentation process and 

accompanying software changes will require a full year. Absent compelling reasons, 

EPSA argues that the Commission should reject the proposed implementation timeline 

and set a new timeline that accommodates actual implementation issues so as not to defer 

any longer the benefits of Order No. 890. 
Docket No. RM08-19-000, et al. - 55 - 

Commission Determination

95. As approved, the Reliability Standards shall become effective on the first day of 

the first calendar quarter that is twelve months beyond the date that the Reliability 

Standards are approved by all applicable regulatory authorities. The Commission finds 

that the approved implementation schedule strikes a reasonable balance between the need 

for timely reform and the needs of transmission service providers and transmission 

operators to make adjustments to their calculations of available transfer capability, 

capacity benefit margin and transfer reliability margin. To the extent necessary, we 

clarify that, under this plan, the Reliability Standards shall become effective on the first 

day of the first quarter occurring 365 days after approval by all applicable regulatory 

authorities. Approval by the Commission will be effective 60 days after the date of 

publication of this Final Rule in the Federal Register. If a transmission service provider 

or transmission operator is unable to implement these Reliability Standards within the 

time allowed, requests for extension should be considered through NERC’s enforcement 

and compliance program. 

3. Implementation Document Audits

a. Authority to Direct Audits

Comments

96. Many commenters expressed concern that the Commission’s proposal to direct 

NERC to conduct audits of the available transfer capability, capacity benefit margin and 

transfer reliability margin implementation documents would be an inappropriate use of 
Docket No. RM08-19-000, et al. - 56 - 

 

the Commission’s authority under section 215 of the FPA.69 They contend that the 

proposed audits would engage NERC in the Commission’s market oversight functions, 

and expand the scope of the ERO’s delegated responsibilities beyond its statutory duty to 

develop and enforce Reliability Standards to ensure the reliability of the Bulk-Power 

System. 

97. NERC states that section 215 recognizes the distinction between reliability matters 

(where the Commission is to give “due weight to the technical expertise of the ERO”), 

and matters affecting competition (where the Commission is to give no such deference). 

NERC states that, while it understands that consistent treatment of transmission 

customers in functions related to competitions and markets is an important part of the 

Commission’s open access policies, this is not within NERC’s mandate to address as the 

ERO. NERC contends that the Commission’s proposed directive blurs the line between 

commercial interests and reliability interests and is not based on an objective evaluation 

of the impact to the reliability of the Bulk-Power System. 

98. NERC contends, and others agree, that the Commission should address its goals 

through business practice standards developed by NAESB and through specific 

Commission rulemakings that direct entities to which the Commission’s market-based 

jurisdiction applies to take action consistent with the Commission’s open access goals. 

69 E.g., NERC, Duke, EEI, EPSA, EEI, Entegra, the Georgia Companies, 

ISO/RTO Council, NRU, NYISO, Pacific Northwest, Public Power Council, Snohomish, 

Puget Sound, SMUD, Joint Municipals, and TANC. 
Docket No. RM08-19-000, et al. - 57 - 

TANC states that NERC’s filing letter was clear that NERC and NAESB have agreed that 

any item that is directly related to the Open Access Same Time Information System or 

other commercial interactions between customers and transmission providers are within 

the scope of NAESB activities. TANC points out that NERC’s filing letter states 

repeatedly that the focus of the proposed Reliability Standards is to address only the 

reliability, not commercial, aspects of available transmission. 

99. Similarly, ISO/RTO Council agrees that the Commission should pursue such 

commercial concerns through another forum such as the NAESB standards. ISO/RTO 

Council expresses concern that the Commission’s proposed directive could undermine 

the coordination efforts between NERC and NAESB on these issues. In addition, 

ISO/RTO Council contends that the NOPR overstates reliability concerns associated with 

the standards and that the Commission lacks justification for additional directives. 

ISO/RTO Council states that overestimation and hence overselling of ATC can result in 

potential or actual violations of system operating limits and interconnection reliability 

operating limits but claims there has not been a single incident in which a system 

operating limit and interconnection reliability operating limit has been violated due to the 

overselling of available transfer capability. 

100. ISO/RTO Council states that the subject of the proposed audits is not related to 

compliance with NERC Reliability Standards or reliability in any way. ISO/RTO 

Council argues that such audits are not in themselves Reliability Standards compliance 

audits which are appropriately conducted by the ERO and its Reliability Entities through 
Docket No. RM08-19-000, et al. - 58 - 

 

a set schedule. Rather, ISO/RTO Council argues, the proposed audits are designed to 

allow the Commission and others to replicate and verify calculations to satisfy a 

competition-related concern. 

101. EEI contends that a Reliability Standard must address a reliability concern that 

falls within the statutory framework of section 215. EEI further contends that the 

purpose of a Reliability Standard may not extend beyond the reliable operation of the 

Bulk-Power System. EEI states that it is appropriate for the Commission to determine if 

a Reliability Standard is unduly discriminatory.70 But, EEI contends, there is a difference 

between a Reliability Standard that is not unduly discriminatory and a standard that 

furthers open access goals that are not a part of the reliable operation of the Bulk-Power 

System. EEI states that the potential discrimination described in the NOPR is related to 

the provision of transmission service under an OATT and, to the extent the Commission 

or others believe such discrimination exists, the Commission has the authority and 

jurisdiction to address such discrimination under sections 205 and 206 of the FPA. 

According to EEI, it is imperative that the ERO maintain focus on its reliability duties 

70 Citing Rules Concerning Certification of the Electric Reliability Organization; 

Procedures for the Establishment, Approval, and Enforcement of Electric Reliability 

Standards, Order No. 672, 71 FR 8662 (Feb. 17, 2006), FERC Stats. & Regs. ¶ 31,204, at 

P 332 (2006); order on reh’g, Order No. 672-A, 71 FR 19814 (Apr. 18, 2006), FERC 

Stats. & Regs. ¶ 31,212 (2006). 
Docket No. RM08-19-000, et al. - 59 - 

 

rather than taking on additional duties to police implementation of tariffs and 

comparability issues.71

102. EEI and Entegra separately ask the Commission to clarify that, under Order 

No. 890, transmission service providers are required to adhere to the Commission’s 

policies regarding non-discriminatory open access transmission service in their exercise 

of discretion under the standards. They also ask the Commission to clarify that it will 

retain jurisdiction under Order No. 890 after approval of the MOD Reliability Standards 

to remedy any undue discrimination that may result from the implementation of these 

standards by individual transmission operators or transmission service providers. Entegra 

separately argues that while it may be necessary and appropriate for the Commission to 

rely on the NERC process to develop requirements that are solely related to reliability, 

the Commission cannot and should not abdicate its statutory authority to prevent undue 

discrimination by delegating to NERC its responsibility to enforce its open access 

requirements. 

103. Although commenters such as NRU, Pacific Northwest, Public Power Council, 

Snohomish and SMUD agree that undue discrimination in transmission service must be 

addressed, they also contend that such a goal is not a statutory purpose that Reliability 

Standards are intended to address. Puget Sound agrees, stating that available transfer 

capability calculations have little impact on reliability. SMUD states that it is troubled by 

71 See also Duke, NYISO and TANC comments. 
Docket No. RM08-19-000, et al. - 60 - 

language in the NOPR that suggests that commercial concepts be addressed by the 

Reliability Standards, even where no clear nexus to reliability exists. NRU, Pacific 

Northwest, Public Power Council, and Snohomish state that the Commission has 

provided no reliability-based justification for the proposed audit directive and that the 

proposal cannot be supported on the basis of reliability. 

104. The Joint Municipals agree that the Commission has not articulated a sufficient 

statutory basis for the proposed audits. The Joint Municipals state that the courts have 

been clear that the Commission must be rigorous in identifying the statutory authority 

under which it proceeds. The Joint Municipals comment that the Commission is charged 

with the responsibility to ensure non-discrimination in the provision of transmission 

service under sections 205, 206 and 211A of the FPA; whereas section 215 clearly 

identifies reliability as the only purpose of the ERO regime. Accordingly, the Joint 

Municipals ask the Commission to make clear that in the exercise of its prosecutorial 

discretion, it will ensure that the Commission and NERC enforcement processes will be 

focused on violations of the proposed Reliability Standards that threaten system 

reliability. The Joint Municipals argue, however, that a review of Order Nos. 890, 693 

and the NOPR make clear that the impetus for developing a consistent, transparent 
Docket No. RM08-19-000, et al. - 61 - 

approach to available transfer capability lies in the Commission’s concern over 

discrimination in the provision of transmission service, rather than system reliability.72

105. By contrast, EPSA states that it supports and applauds the Commission’s efforts to 

meld the reliability goals of Order No. 693 and the non-discriminatory goals of Order No. 

890. EPSA contends that the contributions that market mechanisms make to system 

reliability, and the need to preserve the positive link between reliability and markets, is a 

significant dimension of the new Reliability Standards development process. EPSA 

commends the Commission for recognizing the connection between the MOD Reliability 

Standards and the initiative to reform Order No. 890 to address existing opportunities for 

to discriminate against competitive power suppliers. EPSA states that Order Nos. 890 

and 693 articulated serious concerns regarding the lack of clarity, transparency and 

uniformity in the critical calculations pertaining to one of the most fundamental aspects 

of the wholesale Bulk-Power System from both a reliability and commercial perspective. 

Commission Determination

106. The Commission hereby adopts the NOPR proposal to direct the ERO to conduct 

an audit of the various implementation documents developed by transmission service 

 72 Citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 83 (stating that the 

“purpose of increasing consistency and transparency of [available transfer capability] 

calculations is to reduce the potential for undue discrimination in the provision of 

transmission service.”) See also NOPR, FERC Stats. & Regs. ¶ 32,641 at P 2 (stating that 

the proposed Reliability Standards “address the potential for undue discrimination by 

requiring industry-wide transparency and increased consistency regarding all components 

of the [available transfer capability] methodology and certain definitions, data, and 

modeling.” 
Docket No. RM08-19-000, et al. - 62 - 

 

providers to confirm that the complete available transfer capability methodologies 

reflected therein are sufficiently transparent to allow the Commission and others to 

replicate and verify those calculations. The Commission clarifies that these audits are not 

intended to address the competitive effects of these MOD Reliability Standards.73 

Instead, the audit should review each component of available transfer or flowgate 

capability, including the transmission service provider’s calculation of capacity benefit 

margin and transmission reliability margin, for transparency and verifiability to ensure 

compliance with the MOD Reliability Standards. In the course of its audit, NERC is 

directed to identify any parameters and assumptions that are not sufficiently specific or 

transparent to allow the Commission and others to replicate and verify the results. 

107. The Commission disagrees with commenters asserting that the scope of this audit 

is irrelevant to the Reliability Standards or the reliability of the Bulk-Power System. 

Requirement R3.1 of MOD-001-1 requires transmission service providers to include in 

their available transfer capability implementation documents information describing how 

the selected methodology (or methodologies) has been implemented. Transmission 

service providers are to provide enough detail for the Commission and others to validate 

the results of the calculation given the same information used by the transmission service 

provider. Thus, Requirement R3.1 of MOD-001-1 requires transmission service 

providers to include enough information in their available transfer capability or available 

73 See infra section III.3.b.ii. 
Docket No. RM08-19-000, et al. - 63 - 

 

flowage capability implementation documents to confirm that the respective 

methodologies reflected therein are sufficiently transparent to allow the Commission and 

others to replicate and verify those calculations. Consequently, the audit is directly 

relevant to compliance with the Reliability Standards as proposed by the ERO and 

approved by the Commission in this Final Rule. 

108. As described above, the Reliability Standards approved herein are the result of a 

long process before the Commission. In Order No. 890, the Commission, among other 

things, expressed concern that a lack of consistent, industry-wide available transfer 

capability calculation standards poses a threat to the reliable operation of the Bulk-Power 

System.74 In light of these concerns, the Commission directed public utilities, working 

through the NERC Reliability Standards development process, to develop Reliability 

Standards for the consistent and transparent calculation of available transfer capability.75 

One month later, the Commission issued Order No. 693, which directed the ERO to 

modify nine out of ten approved MOD Reliability Standards to be consistent with the 

requirements in Order No. 890. Thus, the MOD Reliability Standards approved here 

today are the result of efforts by the Commission, the ERO and industry to address 

concerns related to the reliable operation of the Bulk-Power System. 

74 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 195. 

75 Id. P 196. 
Docket No. RM08-19-000, et al. - 64 - 

 

109. The Commission clarifies that it is not directing the ERO to perform a 

market-based analysis of the competitive effects of the Reliability Standards approved 

herein. Although the ERO should attempt to develop Reliability Standards that have no 

undue negative effects on competition,76 the ERO’s statutory functions are properly 

focused on the reliability of the Bulk-Power System and the Commission does not intend 

to broaden that focus here. The Commission reiterates that a proposed Reliability 

Standard should not unreasonably restrict available transmission capability on the 

Bulk-Power System beyond any restriction necessary for reliability and should not limit 

use of the Bulk-Power System in an unduly preferential manner. The Reliability 

Standard should not create an undue advantage for one competitor over another.77 

Nonetheless, pursuant to sections 205 and 206 of the FPA, the Commission shall remain 

the final arbiter of undue discrimination. The MOD Reliability Standards approved in 

this Final Rule require transmission service providers to document their methodologies 

for calculating available transfer capability or available flowgate capability in a 

transparent and consistent manner. Compliance with these requirements is essential to 

reducing the threat posed to the reliable operation of the Bulk-Power System, particularly 

76 Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 332. 

77 Id.
Docket No. RM08-19-000, et al. - 65 - 

 

with respect to the inability of one transmission provider to know with certainty its 

neighbors’ system conditions affecting its own available transfer capability values.78 

110. Specifically, each of the methodologies for calculating available transfer capability 

or available flowgate capability provides an algorithm for calculating the respective 

values. Each of these algorithms requires values for capacity benefit margin and transfer 

reliability margin. For example, Requirement R10 of MOD-028-1 states: 

[available transfer capability] = [total transfer capability] – [existing transmission 

commitments] – [capacity benefit margin] – 

[transfer reliability margins] + postbacks + 

counterflows. 

Thus, in order to validate the results of the available transfer capability or available 

flowgate capability calculations, the Commission and others must be able to validate the 

calculations for capacity benefit margin and transfer reliability margin. Accordingly, the 

Commission directs the ERO to audit the capacity benefit margin and transfer reliability 

margin implementation documents, created pursuant to MOD-004-1 and MOD-008-1 

respectively, to ensure that these documents include information, in such detail that, 

given the same information, the results of the capacity benefit margin or transfer 

reliability margin calculation can be validated. 

78 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 195. 
Docket No. RM08-19-000, et al. - 66 - 

111. Although the Commission directs the ERO to conduct audits to ensure compliance 

with the requirements of the MOD Reliability Standards, the Commission will remain 

vigilant in its efforts to reduce the potential for undue discrimination in the provision of 

transmission service pursuant to its authority under sections 205 and 206 of the FPA. 

Accordingly, transmission customers and neighboring transmission providers will have 

the opportunity to submit complaints pursuant to section 206 of the FPA, if they believe 

that a transmission provider is using assumptions or parameters in available transfer 

capability calculations in an unduly discriminatory or preferential manner.79 

b. Performance of Audits

Comments

112. Many commenters, including NERC, indicate that NERC lacks the expertise to 

conduct the proposed audits. These commenters suggest that Commission staff is more 

suited to perform the audits that pertain to market issues. Others, such as EPSA, support 

the proposed audits but recognize that NERC staff may not have sufficient knowledge 

 79 The ERO is to conduct audits to ensure compliance with the MOD standards to 

assure the reliable operation of the grid. Further, the Commission is not directing that the 

scope of the audit include an active search or review of anomalous events or unduly 

discriminatory behavior. If, however, in the course of an audit the ERO happens to 

identify any assumptions or parameters that appear anomalous, that may appear to cause 

available transfer capability calculation results to be skewed toward a particular result 

even if the implementation documents can be validated according to Requirement R3 of 

MOD-001-1, or that appear to violate NERC’s market-reliability interface principles that 

the Commission acknowledged in Order No. 672, the ERO is free to notify the 

Commission’s Office of Enforcement of such anomalies. 
Docket No. RM08-19-000, et al. - 67 - 

and skill for the task. Other commenters ask for clarification regarding the scope and 

details of such audits. NERC and others contend that the proposed 180-day deadline for 

NERC to complete the audits is overly-burdensome and unrealistic, while Entegra 

supports the NOPR proposal to complete the audits within 180-days of the effective date 

of the Reliability Standards. 

i. NERC Expertise

113. NERC indicates that obtaining personnel with the technical expertise needed to 

evaluate the implementation of these audits will result in staffing challenges that could be 

more complex than the Commission foresees. NERC expresses concern that, if the 

Commission expands the role of the ERO to begin enforcement of open access service, it 

would not be able to perform the audits with its current staff and would therefore need to 

hire new employees or consultants. Moreover, NERC contends that it may prove 

extremely difficult to locate and acquire new employees or consultants with the 

appropriate qualifications to not only review an implementation document for its 

engineering merits but also for its commercial implications. 

114. Several commenters agree that NERC and the Regional Entities lack the ability, 

experience, authority or staff determine whether the Commission or transmission 

customers have sufficient and accurate information for commercial and economic 
Docket No. RM08-19-000, et al. - 68 - 

 

purposes or to ensure compliance with the competition goals of Order No. 890.80 The 

Georgia Companies point out that the Reliability Standards were developed by NERC 

using industry experts on reliability, not necessarily experts on the commercial or 

regulatory implications of undue discrimination in the provision of transmission service. 

Similarly, TAPS and TANC contend that the Commission should not require NERC to 

divert its limited resources to cover market oversight and competition issues. EPSA 

argues that if both the reliability goals of Order No. 693 and the non-discriminatory 

access goals of Order No. 890 become the responsibility of NERC and the regional 

reliability entities, the achievement of each will be diffused. EPSA further contends that 

a reliability audit cannot be a substitute for an audit of transmission access practices and 

measures. 

115. Some commenters recommend that, if the Commission is interested in auditing the 

implementation documents to address commercial concerns, the Commission itself 

should perform the audits.81 For example, APPA states that the role of detecting and 

remedying undue discrimination properly falls upon the Commission, acting in an audit 

and compliance role or acting upon customer complaints that transmission service 

providers or transmission operators have failed to fully comply with transparency 

obligations. Puget Sound states that the Commission has an established method to 

80 E.g., APPA, Cottonwood, EEI, EPSA, NRU, Pacific Northwest, Public Power 

Council, Puget Sound, Joint Municipals and Snohomish. 

81 E.g., Cottonwood, EEI, EPSA, Puget Sound, TAPS and TANC. 
Docket No. RM08-19-000, et al. - 69 - 

conduct such audits – the OATT process. If the Commission chooses to direct NERC to 

conduct these audits, Entegra argues that NERC staff should be required to conduct the 

audit under the guidance of Commission staff. 

ii. Audit Scope

116. Several parties also question the intended scope of the proposed audits.82 For 

example, Entegra contends that the Commission should specify in greater detail the 

contents of the audit with Commission staff acting as subject matter experts with respect 

to the Commission’s policies for non-discriminatory open access transmission service. 

To the extent an audit team identifies an item in an implementation document as unduly 

discriminatory or preferential, or otherwise does not comply with the requirements of 

Order Nos. 890 and 693, Entegra recommends that the Commission should require the 

transmission service provider to modify the item during the audit process as appropriate. 

Entegra states that the audit report should identify and document all areas where the 

implementation document did not comply with Order Nos. 890 and 693 and explain how 

the non-compliance was corrected. Further, Entegra suggests that the Commission 

should specify that the audit findings are preliminary and that it will establish notice and 

comment procedures for the initial audit report. Finally, Entegra recommends that the 

Commission should commit to reopen the audit and/or direct any necessary modifications 

to the implementation documents if the comments of interested parties indicate that any 

 82 E.g., Entegra, EPSA, the Georgia Companies, ITC Companies, NYISO, and 

Puget Sound. 
Docket No. RM08-19-000, et al. - 70 - 

items in the implementation documents are unduly discriminatory or preferential or 

otherwise do not comply with the Commission’s open access requirements in Order 

Nos. 890 and 693. 

117. The Georgia Companies recommend that the Commission describe how it 

proposes the Commission and others should be able to replicate and verify results and 

allow proper time for NERC and the industry to determine a plan that meets the 

Commission’s proposals as well as state and regional requirements. The Georgia 

Companies also ask that the Commission limit its review of capacity benefit margin and 

transmission reserve margin implementation documents to their effect on reliability, not 

undue discrimination. 

118. EPSA recommends the Commission convene a technical conference to clarify the 

audit scope, responsibilities and jurisdictional questions. In addition, EPSA contends that 

the Commission needs to have a process to handle complaints as they arise. 

119. Puget Sound states that the Commission needs to rationalize the OATT 

enforcement regime, which its staff oversees, and the NERC reliability rule enforcement 

regime, as they will both apply to the same total transfer capability/available transfer 

capability concepts. Puget Sound states that the Commission must be absolutely clear 

that the regimes, as they both address available transfer capability calculations, are 

completely consistent and that there is no interpretation gap between enforcement 

personnel and auditors from the two separate entities. Puget Sound contends that this is 

necessary because there is a significant risk of conflicting or at least inconsistent 
Docket No. RM08-19-000, et al. - 71 - 

interpretations and questions the appropriateness of having two enforcement regimes 

cover the same issue. 

120. NYISO expresses concern that the proposed audits might be interpreted to require 

NYISO to publicly disclose confidential market and transmission information in its 

implementation document. NYISO argues that requiring independent system operators 

(ISOs) and regional transmission organizations (RTOs) to reveal information, such as 

transmission flow utilization variables, would place them in a position of choosing to 

comply with the NERC available transfer capability replication requirement or internal 

codes of conduct that forbid ISOs and RTOs from revealing such information. NYISO 

contends that it is not necessary for confidential information to be revealed in order to 

allow market participants to replicate available transfer capability calculations. 

Accordingly, NYISO asks the Commission to clarify that its audit requirement is not 

meant to require ISOs and RTOs to make confidential information publicly available, and 

that other methods can be used to allow market participants to replicate available transfer 

capability calculations without such disclosure. 

121. The ITC Companies contend that the audit process should be strengthened to 

effectively detect evidence of oversubscription or underutilization of the transmission 

system and ensure that the commercial aspect of the available transfer capability closely 

matches the system available transfer capability calculations. The ITC Companies 

suggest, as an example, an audit of adjacent transmission service providers where they 

both calculate the available transfer capability or available flowgate capability for the 
Docket No. RM08-19-000, et al. - 72 - 

same flowgates or paths. The ITC Companies state that, usually, the two calculations 

should have similar results and that any major difference would be the result of 

differences in assumptions or study parameters. In addition, the ITC Companies 

comment that the Commission should open up the results of the NERC audit for further 

comments prior to directing NERC to modify the Reliability Standards to address any 

lack of transparency in the calculation of ATC and each of its components. 

iii. Audit Timeline

122. NERC, and other commenters, oppose the 180-day deadline for NERC to 

complete the audits.83 NERC contends that the imposition of a 180-day deadline to 

complete these audits places a higher priority on these issues than is warranted. NERC 

states that consistency in available transfer capability practices (or the lack thereof) in the 

treatment of transmission has a relatively low reliability impact on the Bulk-Power 

System compared to numerous other core areas under which NERC has responsibilities. 

NERC states that under its Commission-approved rules, NERC must conduct an audit of 

users, owners and operators of the Bulk-Power System every three years. NERC 

contends that the NOPR provides no explanation of the reliability benefits that would 

necessitate an audit cycle accelerated beyond this three year schedule. In addition, 

NERC contends that if the Commission insists on broadening NERC’s responsibilities, 

NERC will need more than 30 days to develop and submit a timeline for the completion 

 83 E.g., APPA, Bonneville, ColumbiaGrid, Georgia Companies, TANC and TAPS. 
Docket No. RM08-19-000, et al. - 73 - 

of these audits. NERC asks that the Commission allow the ERO sufficient time to 

appropriate consider the best ways to restructure its resources in light of its new 

responsibilities. 

123. APPA agrees with NERC stating that the Commission’s proposed timeline is 

potentially very burdensome. APPA, TANC and TAPS state that the proposed timeline 

will likely divert scarce NERC and registered entity staff resources from other tasks that 

are more central to NERC’s responsibilities as the ERO. They recommend that such 

audits take place on the normal three-year or five-year audit cycles applicable to these 

reliability functions. The Georgia Companies state that full audits with on-site visits of 

each transmission owner and transmission service provider likely cannot be completed 

within 180 days. ColumbiaGrid suggests that NERC should be permitted to audit a 

representative sample of entities rather than every single one and then assess whether a 

broader audit is necessary. 

124. By contrast, Entegra suggests that the Commission should require NERC to 

complete the proposed audit within 180 days of the publication of this Final Rule. 

Entegra points out that, as proposed, the proposed audit will not be due until 18 to 21 

months from the approval date. Entegra contends that NERC has not explained why 

drafting the implementation documents and making the corresponding changes to 

software and operating procedures will require 12 to 15 months after approval. 

Accordingly, Entegra suggests that the Commission should require all transmission 

service providers to finalize their implementation documents and submit to NERC within 
Docket No. RM08-19-000, et al. - 74 - 

90 days of the approval date and require NERC to complete the audit within 90 days after 

receipt of these implementation documents. Entegra states that transmission providers 

will have to complete their implementation documents well in advance of the actual 

implementation. Entegra argues that requiring the audit before the effective date would 

allow NERC and the Commission opportunity to identify and remedy – at the front end – 

any individual or systematic problems that NERC of the Commission find in the 

transmission service provider implementation documents. 

Commission Determination

125. While we adopt the NOPR proposal to direct NERC to conduct an audit, we are 

persuaded by the comments of the ERO and others to modify the NOPR proposal 

regarding certain details on implementation of the required audits. First, as already 

discussed above, the Commission will not require the ERO to perform an audit that 

requires the ERO to assess whether a transmission operators’ or transmission service 

providers’ available transfer capability methodology provides opportunities for undue 

discrimination or preference. Rather, the ERO audits must focus on compliance with the 

provisions of the MOD Reliability Standards. In accord with the position of numerous 

commenters, Commission staff is in a more appropriate position to analyze marketrelated issues. Thus, the ERO must retain information and material gathered during the 

course of its audit and make it available to Commission staff upon request, so as to allow 

Commission staff to inquire into possible anti-competition concerns. 
Docket No. RM08-19-000, et al. - 75 - 

126. Moreover, the Commission is persuaded that the ERO should conduct the audits in 

the due course of its periodic, three-year audit cycle, i.e., these Reliability Standards 

should be added to the ERO’s list of actively monitored Reliability Standards. The 

Commission believes that these modifications to the NOPR proposal address the 

concerns of the ERO and others regarding the expertise of the ERO to conduct the audits 

and the availability of ERO resources to conduct the audits in a more limited period of 

time. 

127. The audits directed herein should not displace any of NERC’s existing scheduled 

audits or priorities. If NERC is unable to perform the audits with current staff without 

sacrificing other audit priorities, it can seek additional resources to perform the audits. 

Since the MOD Reliability Standards will not become effective until more than one year 

from Commission approval, NERC can request any additional funding necessary to 

undertake the audits in its 2011 business plan and budget proposal. Thus, NERC will 

have sufficient opportunity to perform the audits without any undue burden. 

128. We decline to direct how the ERO should conduct the MOD Reliability Standards 

audit, as requested by some commenters. We believe that our action to focus the ERO 

audit on compliance with the requirements of the Reliability Standards, matches the 

scope of the audits to the ERO’s expertise. The ERO should be fully capable of 

developing an audit to measure compliance with the requirements of its Reliability 

Standards. In directing this audit, the Commission does not expect NERC’s staff to have 

expert knowledge of the competition requirements of Order No. 890. 
Docket No. RM08-19-000, et al. - 76 - 

 

129. If the Commission determines upon its own review of the data, or upon review of 

a complaint, that it should investigate the implementation of the available transfer 

capability methodologies, the Commission will need access to historical data. 

Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our 

regulations, the Commission directs the ERO to modify the Reliability Standards so as to 

increase the document retention requirements to a term of five years, in order to be 

consistent with the enforcement provisions established in Order No. 670.84

130. With regard to concerns raised by commenters regarding the non-disclosure of 

confidential information, we expect the ERO to conduct the MOD Reliability Standards 

audits consistent with section 1500 of NERC’s Rules of Procedure, which provides 

detailed rules for the protection of confidential information. Section 1505 of NERC’s 

Rules specifically addresses the ERO’s provision of confidential information to the 

Commission or another governmental agency in response to a request for information by 

that agency. Likewise, the implementation documents will be made publicly available 

through the corresponding NAESB business standards, approved concurrently with this 

Final Rule, which incorporate appropriate confidentiality protections.85 

84 Prohibition of Energy Market Manipulation, Order No. 670, 71 FR 4244 

(Jan. 26, 2006), FERC Stats. & Regs. ¶ 31,202, at P 63 (2006) (citing 28 U.S.C. § 2462 

(2000)). 

85 See Standards for Business Practices and Communication Protocols for Public 

Utilities, Order No. 676-E, 129 FERC ¶ 61,162 (2009). 
Docket No. RM08-19-000, et al. - 77 - 

131. As indicated above, we are persuaded by the commenters that the proposed 

180-day time frame for conducting the MOD Reliability Standards audits is not practical, 

and likely not feasible. Upon further consideration, the Commission hereby directs the 

ERO to conduct these audits in the course of its periodic, three-year audits of users, 

owners and operators of the Bulk-Power System. The ERO shall begin this audit process 

60 days after the implementation of these Reliability Standards. On an annual basis, to 

commence on 180 days after the implementation of the Reliability Standards approved 

herein, the ERO shall file the audit reports (or the results of its audit in any other format) 

with the Commission.86 

c. Additional Requirements to Prevent Undue 

Discrimination

NOPR Proposal

132. In the NOPR, the Commission sought 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. 

Comments

133. ISO/RTO Council contends that the proposed MOD Reliability Standards offer the 

appropriate level of discretion in the calculation of the various parameters including the 

 86 The Commission does not anticipate allowing an opportunity for public 

comment on the filed audit reports. 
Docket No. RM08-19-000, et al. - 78 - 

ATC, and that the discretion afforded cannot be used to unduly discriminate the 

provisions of the transmission service. Accordingly, ISO/RTO Council believes that no 

additional requirements should be directed in this proceeding. It is not possible to 

identify and state all assumptions in the requirements for the given set of Reliability 

Standards. 

134. SMUD and Salt River contend that the Reliability Standards may not lawfully be 

expanded to include matters that do not impact the reliability of the Bulk-Power System, 

such as the NAESB business practices. They contend that incorporating NAESB 

business practices and open access concepts in the Reliability Standards creates 

confusion about how the Reliability Standards will be applied. SMUD states, as an 

example, that it is not subject to the NAESB business practices and has not been involved 

in their development. SMUD also points out that the NAESB standards are subject to 

change by Commission order. Similarly, SMUD contends that the Reliability Standards 

should not be melded with the Commission’s open access policies because such policies 

do not apply to SMUD. Salt River also argues that allowing the Reliability Standards to 

be subject to change by the Commission, NAESB or any other third party could create 

situations where third-party revisions of such regulations or business practices could be 

construed as effectively modifying the Commission-approved Reliability Standards. 

Accordingly, SMUD and Salt River argue that compliance with these Reliability 

Standards must be governed by the four corners of the standard and not incorporate by 
Docket No. RM08-19-000, et al. - 79 - 

reference or otherwise NAESB business practices or the Commission’s open access 

policies. 

Commission Determination

135. As the Commission stated in the NOPR, 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 Commission disagrees with ISO/RTO Council’s argument that 

the discretion afforded in these Reliability Standards cannot be used to unduly 

discriminate the provisions of the transmission service. It is possible, for example, for a 

transmission service provider to use parameters and assumptions that skew its available 

transfer capability values toward a particular result in a way that discriminates against 

certain types of customers. As discussed above, the Commission accepts these risks and 

expects that they will be mitigated through complaints as well as the Commission’s own 

market oversight authority. 

136. In response to SMUD and Salt River, the Commission notes that the MOD 

Reliability Standards do not incorporate the NAESB standards. NERC and NAESB 

worked together to create two, distinct sets of standards with overlapping interests. The 

NAESB standards impose certain posting requirements of the available transfer capability 

information generated by these MOD Reliability Standards but compliance with the 
Docket No. RM08-19-000, et al. - 80 - 

MOD Reliability Standards does not depend upon compliance with the NAESB 

standards. 

B. Modification of the Reliability Standards

1. MOD-001-1

a. Availability of the Implementation Documents

NOPR Proposal

137. In the NOPR, the Commission expressed concern that the Reliability Standards 

potentially restrict the disclosure of the available transfer capability, capacity benefit 

margin, and transmission reliability margin implementation documents. Requirements 

R4 and R5 of MOD-001-1 requires transmission service providers to provide a current 

available transfer or flowgate capability implementation document to the following 

entities and to notify the same entities before implementing a new or revised 

implementation document: each planning coordinator, reliability coordinator, and 

transmission operator associated with the transmission service provider’s area; each 

planning coordinator and reliability coordinator adjacent to the transmission service 

provider’s area; and, each transmission service provider whose area is adjacent to the 

transmission service provider’s area. Similarly, Requirement R2 of MOD-004-1, 

requires transmission service providers maintaining to capacity benefit margin to make 

available its current capacity benefit margin implementation document to the following 

entities: transmission operators, transmission service providers, reliability coordinators, 

transmission planners, resource planners, and planning coordinators that are within or 
Docket No. RM08-19-000, et al. - 81 - 

 

adjacent to the transmission service provider’s area, and to the load serving entities and 

balancing authorities within the transmission service provider’s area, and notify those 

entities of any changes to the implementation document prior to the effective date of the 

change. Finally, Requirement R3 of MOD-008-1, requires transmission operators using 

transfer reliability margin to make available its transfer reliability margin implementation 

document, and if requested, underlying documentation, to any of the following who make 

a written request no more than 30 calendar days after receiving the request: transmission 

service providers, reliability coordinators, planning coordinators, transmission planners, 

and transmission operators. 

138. The Commission pointed out that NERC did 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 documents. Although 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 stated that it is important for reliability purposes to require disclosure of the 

implementation documents to a broader audience than provided in the Reliability 

Standards.87 The Commission explained that its jurisdiction under section 215 of the 

FPA is broader than its jurisdiction to require compliance with the NAESB standards 

87 NOPR, FERC Stats. & Regs. ¶ 32,641 at P 104. 
Docket No. RM08-19-000, et al. - 82 - 

under sections 205 and 206 of the FPA. The Commission stated that these documents 

will describe how the transmission provider implements the Reliability Standards and, 

therefore, should be disclosed by all transmission service providers, not only those who 

are also public utilities. 

139. Therefore, to ensure sufficient transparency, the Commission proposed 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.88 The Commission also sought comment on any 

improvements that may be necessary to improve access by transmission customers to the 

implementation documents. 

Comments

140. NERC objects to the Commission’s proposal to expand the availability of the 

implementation documents. NERC states that the Commission’s proposal crosses the 

line between reliability matters and commercial and open access matters. NERC 

contends that the Commission provides no explanation of how reliability could be 

compromised by not making these implementation documents available to all eligible 

transmission customers. Although NERC agrees that it is critical that reliability entities 

 88 Id. P 105. 
Docket No. RM08-19-000, et al. - 83 - 

 

have access to the necessary information regarding Bulk-Power System reliability, NERC 

contends that transparency related to ensuring open access and consistent treatment for all 

transmission customers is not critical to reliability or within NERC’s area of 

responsibility. 

141. NERC states that the Commission has other tools and authorities to police its open 

access policies. NERC states that its mandate is to ensure the reliability of the BulkPower System. It also states that it has coordinated procedures with NAESB to address 

the appropriate assignment of tasks that could have a reliability or a commercial impact, 

and the actions proposed by the Commission could undermine that coordination. 

Accordingly, NERC asks the Commission to address its desired goals through the 

business practice standards developed by NAESB and through specific Commission 

rulemakings that direct entities to which the Commission’s market-based jurisdiction 

applies to take action consistent with the Commission’s open access goals. 

142. Many commenters agree that the availability of the implementation documents 

should be limited to those entities with a reliability need for such information.89 These 

parties argue that expanding the availability of the implementation documents to entities 

without a reliability need for such information is beyond the ERO’s statutory authority, 

which is limited to ensuring the reliable operation of the Bulk-Power System. Several 

entities agree that any information provided as part of any Reliability Standard should be 

89 E.g., APPA, Bonneville, Duke, EEI, the Georgia Companies, ISO/RTO Council, 

Pacific Northwest, SMUD, Snohomish, TANC. 
Docket No. RM08-19-000, et al. - 84 - 

 

restricted to that which is needed to ensure reliability.90 ISO/RTO Council further argues 

that achieving transparency by making these documents available to the public is not 

related to reliability. Similarly, the Georgia Companies contend that it is beyond the 

scope of NERC’s authority to make these documents available to unregistered entities 

that do not have to comply with the Reliability Standards. 

143. Many commenters also argue that the availability of the implementation 

documents is a business practice issue that should be dealt with in NAESB standards.91

Although parties such as EEI contend that the NAESB standards do not provide sufficient 

confidentiality protections for competitively sensitive information, others, such as APPA 

contend that NAESB is a more appropriate standards development forum with which to 

craft and maintain these business practices and associated confidentiality agreements. 

APPA also suggests that disputes concerning access to such information fall squarely 

within the Commission’s jurisdiction and expertise under sections 205 and 206 of the 

FPA and not within NERC’s responsibilities under section 215 of the FPA. 

144. By contrast, Entegra argues that the Commission should direct the ERO to modify 

MOD-001-1 to require each transmission service provider to make available, upon 

request, all relevant documentation, input data, models, assumptions and other materials 

necessary to replicate the transmission service provider’s available transfer capability 

90 E.g., Bonneville, EEI, SMUD, Snohomish, Salt River. 

91 E.g., APPA, Bonneville, ColumbiaGrid, ISO/RTO Council, Pacific Northwest, 

SMUD, Snohomish, Salt River. 
Docket No. RM08-19-000, et al. - 85 - 

calculations and results and to verify that the transmission service provider has applied its 

methodology and models in a consistent, non-discriminatory manner. If a data item used 

in a calculation is confidential, Entegra suggests it should be so identified in the 

implementation document, and made available subject to a confidentiality or nondisclosure agreement. Entegra also suggests that, because NERC proposes to leave to the 

NAESB process any posting requirements, the NERC Reliability Standard should require 

transmission service providers to provide a complete, regularly updated (i.e., at least once 

per day) list of all of the above materials that are not posted, but are to be made available 

upon request. 

145. Puget Sound also supports the Commission proposal to make the implementation 

documents more broadly available and to impose comparable disclosure requirements on 

non-jurisdictional entities. However, to the extent that the proposed MOD Reliability 

Standards continue to require available transfer capability algorithm documentation, in 

addition to Appendix C to the OATT, the available transfer capability implementation 

document, the capacity benefit margin implementation document, and the transfer 

reliability margin implementation document, Puget Sound contends that such 

documentation obligations are duplicative and overly burdensome. Accordingly, 

Puget Sound recommends the development of a single documentation process for these 

related obligations. Puget Sound contends that it would be confusing to customers and 

counterproductive if the OATT Attachment C documentation is not consistent with the 

NERC required documentation. 
Docket No. RM08-19-000, et al. - 86 - 

146. TAPS supports the Commission’s proposal to make the implementation 

documents available to all customers eligible for transmission service in a manner that is 

consistent with relevant NAESB standards. TAPS contends that it is essential from a 

competitive perspective for customers to have timely access to this data. TAPS also 

contends that the proposed expanded disclosure requirements are consistent with the 

Commission’s obligation to review de novo the competitive impact of the proposed 

standards under section 215(d)(2) of the FPA. TAPS contends that, unless entities who 

purchase transmission service have timely access to the transmission available 

implementation documents, they will not be able to verify the amount of transmission 

that appears to be available, undermining the Commission’s effort to enhance reliability 

and competition through more accurate and transparent calculation of available transfer 

capability. 

Commission Determination

147. As noted in several comments, expanding the availability of the implementation 

documents to entities beyond the registered entities listed in the Reliability Standards 

may stretch the role of the ERO beyond ensuring reliability of the Bulk-Power System 

and could be duplicative of the associated NAESB standard requirements. Therefore, 

upon further consideration, the Commission declines to adopt the NOPR proposal to 

direct the ERO to modify MOD-001-1 to expand the availability of the implementation 

documents beyond those entities with a demonstrated reliability need to access such 

information. Instead, the Commission approves the availability provisions of the 
Docket No. RM08-19-000, et al. - 87 - 

Reliability Standards as written. NERC has provided sufficient justification for limiting 

disclosure of the implementation documents to a discrete set of registered entities that 

have been identified as having a reliability need for such information. 

148. In response to Puget Sound, the Commission finds that the disclosure requirements 

imposed here are not overly burdensome or duplicative of a transmission service 

provider’s obligation to include these available transfer capability algorithms in 

Appendix C to the OATT. The implementation documents developed under the MOD 

Reliability Standards ensure transparency for the sake of the reliable operation of the 

Bulk-Power System whereas the reporting requirements in Attachment C of the OATT 

are designed to reduce opportunities for undue discrimination. Although the algorithms 

may be repeated in both documents, the supporting information and the purpose for 

providing that information differ greatly. Moreover, the disclosure requirements of these 

MOD Reliability Standards are binding on all transmission providers, not just those 

within the Commission’s jurisdiction under sections 205 and 206 of the FPA. 

149. As written, the Reliability Standard requires all transmission service providers to 

make the implementation documents available to designated reliability entities. With the 

modification directed above, the Commission is confident that disclosure will be broad 

enough to ensure the reliable operation of the Bulk-Power System. The Commission’s 

concerns for broad availability of the implementation documents are sufficiently 
Docket No. RM08-19-000, et al. - 88 - 

 

mitigated by the disclosure requirements of the related NAESB standards.92 Specifically, 

NAESB has developed Standard 001-13.1.5, which requires transmission service 

providers to include an available transfer capability information link on OASIS. This 

standard requires that transmission providers post several links on the available transfer 

capability information link, including links to their available transfer capability, capacity 

benefit margin and transfer reliability margin implementation documents. 

150. Relying on the NAESB standards to require appropriate disclosure of the 

implementation documents should also resolve concerns for appropriate confidentiality 

protections. Standard 001-13.1.5 provides that the posting of information on the 

available transfer capability link would be “subject to the Transmission Provider’s ability 

to redact certain provisions due to market, security or reliability sensitivity concerns.” In 

Order No. 890, the Commission acknowledged that a transmission provider may require 

someone seeking access to CEII material or proprietary customer information to sign a 

confidentiality agreement. The Commission expects that the provision in the NAESB 

standard for a transmission provider to redact sensitive information from postings to be 

implemented by a transmission provider subject to their OATT in a manner consistent 

with its obligation to make that information available to those with a legitimate need to 

92 The NAESB standards are approved concurrently with this Final Rule. See

Standards for Business Practices and Communication Protocols for Public Utilities, Order 

No. 676-E, 129 FERC ¶ 61,162 (2009). 
Docket No. RM08-19-000, et al. - 89 - 

access the information, subject to appropriate confidentiality restrictions. Nevertheless, 

any concerns about the NAESB business practices should be raised with NAESB itself. 

151. Nevertheless, the Commission believes that the lists of required recipients of the 

implementation documents may be overly prescriptive and could exclude some registered 

entities with a reliability need to review such information. Accordingly, pursuant to 

section 215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission 

directs the ERO to develop a modification to the Reliability Standards pursuant to the 

ERO’s Reliability Standards development process to require disclosure of the various 

implementation documents to any registered entity who demonstrates to the ERO a 

reliability need for such information. 

b. Dispatch Model Assumptions

NOPR Proposal

152. In the NOPR, the Commission stated its belief that, subject to confirmation by 

NERC through its audit, the Reliability Standards will provide the necessary level of 

transparency and, therefore, the results of the available transfer capability calculations 

will be sufficiently accurate, consistent, equivalent and replicable. Aspects of the 

dispatch model to be used by transmission service providers using available transfer 

capability or available flowgate capability are addressed throughout the Reliability 

Standards. For example, Requirement R3.6 of MOD-001-1 requires transmission service 

providers to include in their implementation documents a description of how generation 

and transmission outages are to be considered in transfer of flowgate calculations. 
Docket No. RM08-19-000, et al. - 90 - 

Requirement R9 of MOD-001-1 requires transmission service providers to provide, upon 

request, information related to unit commitments and order of dispatch, to include all 

designated network resources and other resources that are committed or have the legal 

obligation to run, as they are expected to run. Similarly, Requirement R6.1.2 of 

MOD-030-2 requires transmission service providers to consider unit commitment and 

dispatch order in the calculation of existing transmission capability. 

Comments

153. Cottonwood and Entegra state that the Reliability Standards provide little detail 

and practically no guidelines on the dispatch model to be used in the available transfer 

capability or available flowgate capability calculations. Cottonwood contends that 

despite the lack of clear and measurable requirements, the dispatch model is the most 

significant factor in the calculation of available transfer capability and available flowgate 

capability values. Cottonwood further contends that additional detail will reduce the 

potential for manipulation of flowgate capabilities through the use of dispatch models 

that are not realistic and that, therefore, could lead to undue discrimination in access to 

the transmission system. To reduce the potential for undue discrimination and to improve 

the accuracy of the available transfer capability and available flowgate capability 

calculations, Cottonwood and Entegra ask the Commission to direct the ERO to develop 

detailed requirements for the dispatch model used in these calculations and establish 

measurements to evaluate compliance with the requirements. 
Docket No. RM08-19-000, et al. - 91 - 

 

154. Entegra contends that the Reliability Standards fail to comply with the 

requirement in Order No. 890 that reservations from a generator in excess of the 

generator’s nameplate should not be simultaneously included in the calculation of 

existing transmission commitments.93 Entegra argues that this may cause available 

transfer capability or available flowgate capability calculations to indicate unrealistic 

utilization of transmission capacity associated with over-generation. Entegra requests 

that the Commission require NERC to continue to work on a methodology for the 

appropriate treatment of over-generation. By contrast, ISO/RTO Council argues that the 

Commission should not direct the ERO to modify the Reliability Standard to restrict 

reservations coming out of a generation source to the generation nameplate capacity of 

that facility. ISO/RTO Council contends that there is no reliability impact of generating 

above nameplate capacity because the generator can not generate above its capacity. 

ISO/RTO Council contends that NAESB would be the appropriate organization to 

address the maximum reservation level and that the Commission should not interfere with 

the coordination efforts between NERC and NAESB. 

155. Entegra contends that MOD-001-1 does not adequately address the modeling of 

transmission and generation outages in the models used for monthly available transfer 

capability calculations. Accordingly, Entegra asks the Commission to direct the ERO to 

modify MOD-001-1, Requirements R3.6 and R8, to provide clear guidelines on the 

93 Citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 254. 
Docket No. RM08-19-000, et al. - 92 - 

duration and type of outages to be included in the calculation of monthly available 

transfer capability or available flowgate capability values to ensure that this process is 

transparent and consistent across the various regions. Entegra also contends that 

transmission service providers should be required to update models and available transfer 

capability or available flowgate capability values as soon as practicable after an event 

such as a generation or transmission outage or the discovery of an error in the 

calculations, rather than waiting for the next scheduled update. 

156. Entegra contends that the Commission should direct the ERO to modify 

MOD-001-1 to require transmission operators or transmission service providers to 

periodically review, update, and benchmark their models to actual events used for 

available transfer capability or available flowgate capability calculations. Entegra points 

out that NERC, in its filing, argued that benchmarking is outside the scope of the 

ATC-related Reliability Standards. Entegra states that the updating and benchmarking of 

models to actual events are essential elements of the Commission’s ATC reforms because 

they ensure that the available transfer capability or available flowgate capability values 

will be modeled as accurately as possible. Entegra contends that the Commission should 

require transmission operators and transmission service providers to examine in their 

benchmarking analyses whether their models result in unduly preferential or 

discriminatory treatment of any class of transmission customers or transmission service. 

Entegra also contends that the Commission should require transmission operators and 
Docket No. RM08-19-000, et al. - 93 - 

transmission service providers to use the results of the benchmarking studies to make any 

necessary or appropriate adjustments to their models. 

157. Entegra suggests that the benchmarking and updating requirements in the revised 

standard should ensure that transmission providers’ available transfer capability and 

available flowgate capability models and methodologies comply with the accuracy 

expectations set forth in Order Nos. 693 and 890. Entegra also urges the Commission 

should direct the ERO to revise the Reliability Standards to specify the frequency with 

which transmission operators and transmission service providers must periodically 

review and update their models. Finally, Entegra asks the Commission to direct the ERO 

to develop a modification to the Reliability Standard that would allow stakeholders to 

comment on the results of such studies and participate in the review and updating of the 

available transfer and flowgate capability methodologies. 

158. Cottonwood agrees that the MOD Reliability Standards should include a 

benchmarking process for available transfer capability models and results. Cottonwood 

contends that while an audit of the transmission service providers’ implementation 

documents would help reduce the risk of undue discrimination, only an ongoing 

monitoring and benchmarking process that includes Commission and stakeholder input 

will protect against actual misstatements of available transfer capability values. 

Cottonwood states that it raised this issue during the stakeholder process but was 

informed that benchmarking will be addressed with future standards development efforts. 
Docket No. RM08-19-000, et al. - 94 - 

Commission Determination

159. With respect to the treatment of dispatch modeling assumptions, the Commission 

finds that the proposed requirements adequately address these issues by maintaining 

transmission service providers’ discretion to model their systems effectively. As the 

Commission stated in the NOPR, 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 Commission maintains that 

these 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.94 Any such system conditions or modeling assumptions, however, must be 

made sufficiently transparent and be implemented consistently for all transmission 

customers. 

160. In Order No. 890, the Commission also expressed concern regarding the treatment 

of reservations with the same point of receipt (generator), but multiple points of delivery 

(load), in setting aside existing transmission capacity.95 The Commission found that such 

 94 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 51. 

95 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 245; Order No. 693, FERC 

Stats. & Regs. ¶ 31,242 at P 1033. 
Docket No. RM08-19-000, et al. - 95 - 

 

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.96 Thus we 

will not direct the ERO to develop a modification to address over-generation, as 

suggested by Entegra. Nonetheless, in developing the modifications to the MOD 

Reliability Standards directed in this Final Rule, the ERO should consider generator 

nameplate ratings and transmission line ratings including the comments raised by Entegra 

and ISO/RTO Council. 

96 MOD-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 

August 29, 2008 Filing, Docket No. RM08-19-000, 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 No. 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. 
Docket No. RM08-19-000, et al. - 96 - 

 

161. Nevertheless, the Commission believes that these Reliability Standards would 

benefit from benchmarking requirements, such as those described by Cottonwood and 

Entegra. Dispatch models should reflect technical analysis, i.e., sound engineering, as 

well as operating judgment and experience.97 If so, the available transfer or flowgate 

capability forecasts should be close to actual values. However, changes in system 

conditions, among other variables, can cause differences between calculated and actual 

values for available transfer or flowgate capabilities. Such variations are to be expected. 

If, however, a transmission service provider’s calculations consistently under- or overestimate available transfer or flowgate capability, adjacent systems will be unable to 

effectively model their own transfer or flowgate capabilities, thus resulting in a 

degredation to the reliable operation of the Bulk-Power System. 

162. In Order No. 890, the Commission directed public utilities, working through 

NERC, to modify MOD-010 through MOD-025 to incorporate a periodic review and 

modification of various data models.98 The Commission found that updating and 

benchmarking was essential to accurately simulate the performance of the transmission 

grid and to calculate comparable available transfer capability values. On rehearing, the 

Commission clarified that the models used by the transmission provider to calculate 

97 See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 5 (stating that in order 

for the Commission to determine that Reliability Standard is just and reasonable it must 

find, inter alia, that the Reliability Standard is designed to achieve a specified reliability 

goal and contains a technically sound means to achieve this goal). 

98 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 290. 
Docket No. RM08-19-000, et al. - 97 - 

 

available transfer capability, and not actual available transfer capability values, must be 

benchmarked.99 Updating and benchmarking of models to actual events will ensure 

greater accuracy, which will benefit information provided to and used by adjacent 

transmission service providers who rely upon such information to plan their systems. 

Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our 

regulations, the Commission directs the ERO to develop benchmarking and updating 

requirements to measure modeled available transfer and flowgate capabilities against 

actual values. Such requirements should specify the frequency for benchmarking and 

updating the available transfer and flowgate capability values and should require 

transmission service providers to update their models after any incident that substantially 

alters system conditions, such as generation outages. 

163. The benchmarking and updating requirements directed herein need not be so 

specific that they set a maximum discrepancy between the model and the actual results. 

As stated above, a transmission service provider should retain some discretion to reflect 

unique system conditions or modeling assumptions in its available transmission 

capability methodology. There may be modeling assumptions or actual system 

conditions that result in wide variations between modeled values and actual results. The 

purpose of these benchmarking and updating available transfer and flowgate capability 

values is to increase accuracy by improving transparency. However, the Commission 

99 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 99. 
Docket No. RM08-19-000, et al. - 98 - 

will not go so far as to direct a maximum discrepancy. Similarly, the Commission will 

not require these benchmarking and updating processes be open to stakeholder input once 

the requirements are in place. Allowing stakeholders to participate in a transmission 

service provider’s modeling practices would place an undue burden on transmission 

service providers and threaten their ability to model their systems effectively. 

164. The Commission also believes that the benchmarking requirements directed herein 

should not be designed or used by the ERO to monitor undue discrimination. 

Transmission providers within the Commission’s FPA sections 205 and 206 jurisdiction 

are required to adhere to the Commission’s open access and non-discrimination 

principles. If the information gathered pursuant to NERC’s benchmarking requirements 

provides evidence of undue discrimination against a jurisdictional entity, such 

information should be brought to the Commission’s attention either by the ERO or 

another entity with access to the modeling data. In response, the Commission may 

investigate the alleged behavior pursuant to its authority under sections 205 and 206 of 

the FPA. 

c. Treatment of Network Resource Designations

NOPR Proposal

165. In the NOPR, the Commission observed that NERC has not explained its failure to 

include in each of the available transfer capability methodologies a requirement that base 

generation dispatch schedules will reflect the modeling of all network resources and other 

resources that are committed to or have the legal obligation to run, as they are expected to 
Docket No. RM08-19-000, et al. - 99 - 

run. The Commission stated that it was therefore unclear whether the proposed 

Reliability Standards address the effect of available transfer capability on designating and 

undesignating a network resource. Although the Commission proposed 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 proposed to direct the ERO to develop a 

modification to the Reliability Standards to address these requirements. 

Comments

166. NERC admits that MOD-029-1 does not address the designation of network 

resources, but states that requirement R3.1.3 of MOD-028-1 may address the 

Commission's concern by describing the key components to determining total transfer 

capability, namely: “Unit commitment and dispatch order, to include all designated 

network resources and other resources that are committed or have the obligation to run.” 

The Georgia Companies and Duke agree, also citing to the language of R3.1.3 of 

MOD-028-1. They also argue that MOD-030-2 reflects the modeling of network 

resources and other resources that have the obligation to run, citing to requirements 

R6.1.2 and R6.2.2, which contain language similar to requirement 3.1.3 of MOD-028-1. 

Northwest Utilities, Pacific Northwest state that they support the comments and 

arguments made by NERC. 

167. Puget Sound contends that it is appropriate for the proposed Reliability Standards 

to require a model that best reflects expected conditions for the applicable horizon. 
Docket No. RM08-19-000, et al. - 100 - 

 

Puget Sound argues that the proposed MOD Reliability Standards also should require 

disclosure of the generation profile or dispatch used in the total transfer capability and 

available transfer capability calculations. Puget Sound suggests that incorporating a 

blanket requirement built around the OATT-defined term “designated network resource,” 

will not ensure a model run that best reflects expected conditions. As an example, 

Puget Sound states that if a wind generation resource is designated as a network resource, 

such a designation would not guarantee that the generation is available. Likewise, 

Puget Sound states, designated resources are increasingly undesignated for monthly 

periods but are still run to supply native load using point-to-point or secondary service. 

Thus, Puget Sound contends, it is incorrect to assume that a designated network resource 

runs at a particular load level, based solely on its designation status. Rather, Puget Sound 

contends, the total transfer capability and available transfer capability calculations should 

simply correspond with expected conditions, including an expected dispatch and that the 

dispatch condition be transparent. 

168. TAPS questions the language of the NOPR referring to 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.”100 TAPS contends that the first part of 

this clause could be interpreted as directing NERC to develop modified standards that 

adopt modeling assumptions as to use of network resources that fail to reflect the 

100 Citing NOPR, FERC Stats. & Regs. ¶ 32,641 at P 120. 
Docket No. RM08-19-000, et al. - 101 - 

to 

 confusion. 

flexibility inherent in network service, which allows for economic dispatch of available 

resources. TAPS notes that, even if designated, a network resource does not have to 

operate. TAPS states that the second phrase “as they are expected to run” tempers this 

requirement, but asks the Commission to avoid being prescriptive in the Final Rule as 

how network resource is to be modeled to avoid

169. TAPS also contends that the NOPR proposal does not expressly incorporate, or 

perhaps even leave room for, the concept articulated in Order No. 890-C of reexamining 

the Commission’s undesignation requirements, and in particular the requirement of unitspecific undesignations for off-system sales of system power, in light of better 

information as to their practical impact on the realistic determination of available transfer 

capability. TAPS questions the usefulness of modifying the Reliability Standards to 

require unit-specific undesignations for resources used to serve off-system sales, 

suggesting that such undesignations on a day-ahead basis are not likely to usefully 

enhance the precision of available transfer capability calculations. 

170. TAPS contends that the Commission should initiate a process to reexamine the 

interaction of network resource undesignation requirements with available transfer 

capability calculations. TAPS states that it would be contrary to the Commission's procompetitive policies to discourage beneficial transactions, including firm system sales 

from entities other than the customer's host transmission provider, particularly if it is 

unlikely that available transfer capability calculations would be made significantly more 

precise by imposing unit-specific undesignation requirements on system sales where the 
Docket No. RM08-19-000, et al. - 102 - 

supplier and purchaser do not take network service on the same transmission system. At 

a minimum, TAPS contends, the Final Rule should clearly afford NERC, through its 

standards development process, the flexibility to assess the impact of network resource 

designations and undesignations on available transfer capability determinations and 

report back to the Commission as to its assessment, along with modified Reliability 

Standards as appropriate. TAPS argues that a more flexible directive would enable 

NERC, through its standards development process, to access whether unit-specific 

network resource undesignations are, in fact, needed to allow transmission providers to 

determine available transfer capability when a network customer seeks to make a sale of 

system power to an off-system party. 

Commission Determination

171. The Commission finds that MOD-028-1 and MOD-029-1 fail to address the 

directive in Order No. 693 to specify how transmission service providers should 

determine which generators should be modeled in service when calculating available 

transfer capability.101 Specifically, the Commission directed the ERO to develop a 

modification to the Reliability Standards to specify that base generation schedules used in 

the calculation of available transfer capability will reflect the modeling of all designated 

network resources and other resources that are committed to or have the legal obligation 

 101 See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 119. 
Docket No. RM08-19-000, et al. - 103 - 

to run, as they are expected to run, and to address the effect on available transfer 

capability of designating and undesignating a network resource. 

172. NERC acknowledges that MOD-029-1 fails to address this directive. NERC and 

commenters cite to Requirement R3.1.3 of MOD-028-2 in support of arguments that the 

Reliability Standard reflects the modeling of designated network resources. That 

requirement, however, governs the calculation of total transfer capability, not existing 

transmission commitments. The only information provided as to the effect of designating 

and undesignating a network resource on existing transmission commitments is in 

Requirement R8 of MOD-028-1, which merely states that "the firm capacity set aside for 

Network Integration Transmission Service" will be included. The Reliability Standard 

fails to identify how that firm capacity will be calculated. By comparison, Requirements 

R6.1.2 and R6.2.2 of MOD-030-2 require transmission service providers to calculate 

existing transmission commitments by accounting for the impact of firm network service 

in their transmissions model based on, among other things, unit commitment and dispatch 

order that includes all designated network resources. Requirement R8 of MOD-001-1 

further requires the transmission service provider to perform recalculations at specified 

frequencies to reflect changes over time. 

173. The Commission therefore directs the ERO, pursuant to section 215(d)(5) of the 

FPA and section 39.5(f) of our regulations, to develop a modification to MOD-028-1 and 

MOD-029-1 to specify that base generation schedules used in the calculation of available 

transfer capability will reflect the modeling of all designated network resources and other 
Docket No. RM08-19-000, et al. - 104 - 

resources that are committed to or have the legal obligation to run, as they are expected to 

run, and to address the effect on available transfer capability of designating and 

undesignating a network resource. 

174. With regard to Puget Sound's concern regarding the modeling of designated 

network resources, as noted above MOD-030-2 requires transmission providers to 

account for the impact of firm network service in their transmission models. This 

requirement is flexible enough to allow transmission service providers to account for the 

variable nature of intermittent generation, as well as the economic dispatch of all 

resources, as noted by TAPS. To the extent either Puget Sound or TAPS have additional 

concerns regarding the development of MOD-028-1 and MOD029-1 on this issue, they 

may pursue their concerns through the standards development process as NERC complies 

with the directives above. 

175. The Commission finds that it is premature to consider revisiting its network 

resource policies to reflect the Reliability Standards adopted herein. As discussed above, 

MOD-028-1 and MOD-029-1 fail to address the directives in Order No. 693 to specify 

how transmission service providers should determine which generators should be 

modeled in service when calculating available transfer capability. It would therefore not 

be appropriate for the Commission to revisit network resource policies based on the 

current version of those Reliability Standards. As NERC considers modification to these 

standards, TAPS may participate in the standards development process to address its 
Docket No. RM08-19-000, et al. - 105 - 

concerns regarding the treatment of unit-specific network resource undesignations on the 

calculation of available transfer capability.102

d. Updating Available Transfer Capability and Available 

Flowgate Capability Values

NOPR Proposal

176. In the NOPR, the Commission proposed to approve MOD-001-1 including 

Requirement R8 and MOD-030-2, Requirement R10. These requirements require 

transmission service providers that calculate available transfer capability or available 

flowgate capability to recalculate those values at least one per hour for hourly values, 

once per day for daily values, and once per week for monthly values. 

Comment

177. Entegra contends that the proposed Reliability Standard does not mandate any 

consistency or transparency regarding the timing of updates to available transfer 

capability calculations, nor does it require transmission service providers to consider 

whether such updates should be required more frequently for constrained facilities. 

Entegra states that while Requirement R8 of MOD-001-1 requires transmission service 

 102 In Order No. 890-D, issued concurrently with this order, the Commission 

clarifies that, when a buyer and seller of capacity from a network resource both take 

network service on the same transmission system and the power is delivered under 

section 31.3 of the pro forma Open Access Transmission Tariff (OATT) to another 

transmission system on which the buyer’s network load is located, the seller may support 

the transaction by undesignating its resources on a system basis. Preventing Undue 

Discrimination and Preference in Transmission Service, Order No. 890-D, 129 FERC ¶ 

61,126 (2009). 
Docket No. RM08-19-000, et al. - 106 - 

providers to update hourly, daily, and monthly available transfer capability values once 

every hour, day, or month, respectively, it does not set forth a deadline for such updates, 

nor does it require transmission service providers to disclose when such updates must 

occur, and that therefore the values may have become inaccurate by the time they are 

eventually disclosed. Accordingly, Entegra asks the Commission to direct the ERO to 

revise MOD-001-1, Requirement R8 to include a one-hour time limit for updates to daily 

and monthly available transfer capability values. In addition, Entegra asks the 

Commission to direct the ERO to modify the Reliability Standard to require transmission 

service providers to consider whether more frequent updates are necessary for 

constrained facilities. 

178. Cottonwood contends that Requirement R8 of MOD-001-1 and Requirement R10 

of MOD-030-2 do not address the procedures for determining whether unscheduled or 

unanticipated events, such as unplanned outages or the return of a major transmission line 

earlier than expected, justify the updating of available transfer capability values. 

Cottonwood argues that a lack of such procedures will result in inaccurate available 

transfer capability values and accompanying service issues. Cottonwood argues that, in 

the event of such a material change in system condition, available transfer capability or 

available flowgate capability values should be recalculated more often than proposed in 

the Reliability Standards. At a minimum, Cottonwood argues, the Commission should 

clarify that, for purposes of compliance with its OATT, a transmission service provider 

may not rely on these Reliability Standards as a “safe harbor” for its failure to make more 
Docket No. RM08-19-000, et al. - 107 - 

frequent available transfer capability value adjustments as warranted by changes in 

system conditions. 

Commission Determination

179. We agree that, in order to be useful, hourly, daily and monthly available transfer 

capability and available flowgate capability values must be calculated and posted in 

advance of the relevant time period. Requirement R8 of MOD-001-1 and Requirement 

R10 of MOD-030-2 require that such posting will occur far enough in advance to meet 

this need. With respect to Entegra’s request regarding more frequent updates for 

constrained facilities, we direct the ERO to consider this suggestion through its 

Reliability Standards development process. Further, we agree with Cottonwood 

regarding unscheduled or unanticipated events. Therefore, pursuant to section 215(d)(5) 

of the FPA and section 39.5(f) of our regulations, we direct the ERO to develop 

modifications to MOD-001-1 and MOD-030-2 to clarify that material changes in system 

conditions will trigger an update whenever practical. Finally, we clarify that these 

Reliability Standards shall not be used as a “safe harbor” to avoid other, more stringent 

reporting or update requirements. 

e. MOD-001-1, Consistent Treatment of Assumptions

NOPR Proposal

180. In the NOPR, the Commission expressed concern that the proposed Reliability 

Standards did not preclude a transmission service provider from using data and 

assumptions in a way that double counts their impact on available transfer capability and 
Docket No. RM08-19-000, et al. - 108 - 

thereby skews the amount of capacity made available to others.103 Although the 

Commission recognized that it may be appropriate for some variables to be factored into 

multiple components of the available transfer capability calculation, such as facility 

ratings, the Commission stated that 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. Accordingly, the Commission proposed to direct the ERO, pursuant to section 

215(d)(5) of the FPA and section 35.19(f) of its regulations, to modify the proposed 

Reliability Standards to ensure that they preclude a transmission service provider from 

using data and assumptions in a way that double counts their impact on available transfer 

capability. 

Comments

181. ISO/RTO Council states that the double-counting issue has no measurable impact 

on the reliability of the Bulk-Power System and hence is outside the mandate of the ERO. 

ISO/RTO Council and Pacific Northwest contend that ensuring increased transparency of 

the implementation documents is not critical to reliability or within NERC’s area of 

responsibility as the ERO. Separately, Midwest ISO contends that the Reliability 

Standards as written do not permit an entity to double count the impact of data and 

 103 NOPR, FERC Stats. & Regs. ¶ 32,641 at P 107. 
Docket No. RM08-19-000, et al. - 109 - 

assumptions on available transfer capability calculations and recommends that the 

commission accept the Reliability Standards as proposed. 

182. Likewise, Northwest Utilities and Pacific Northwest comment that the 

Commission’s concern with double-counting is better addressed through a business 

practice than in the Reliability Standards. Northwest Utilities contends that even if a 

transmission service provider were to double-count in the manner the Commission 

suggests, commercial sales of transmission services would be impacted but not reliability. 

Northwest Utilities states that making less available transfer capability available than is 

possible does not imperil Bulk-Power System reliability because the system would be 

used even less than the extent of its capacity. 

183. By contrast, TAPS supports the Commission’s proposal to direct the ERO to 

modify the Reliability Standards to ensure that they do not allow a transmission service 

provider to use data and assumptions in a way that double counts their impact on 

available transfer capability. TAPS contends that transmission providers must not be 

permitted to calculate available transfer capability using data and assumptions that double 

count the impact of factors that would artificially decrease available transmission and 

create the appearance of constraints. TAPS also states that the NOPR proposal is 

consistent with Order No. 890’s effort to enhance reliability and competition through 

more accurate and transparent calculation of available transfer capability. 
Docket No. RM08-19-000, et al. - 110 - 

Commission Determination

184. As proposed, MOD-001-1 does not restrict a transmission service provider from 

double counting data inputs or assumptions in the calculation of available transfer or 

flowgate capability. To the extent possible, available transfer or flowgate capability 

values should reflect actual system conditions. The double-counting of various data 

inputs and assumptions could cause an understatement of available transfer or flowgate 

capability values and, thus, poses a risk to the reliability of the Bulk-Power System. We 

note that, in the Commission’s order accepting the associated NAESB business standards, 

issued concurrently with this Final Rule in Docket No. RM05-5-013, the Commission 

directs EPSA to address its concerns regarding the modeling of condition firm service 

through the NERC Reliability Standards development process.104 We reaffirm here that 

modeling of available transfer capability should consider the effects of conditional firm 

service, including the potential for double-counting. Accordingly, pursuant to section 

215(d)(5) of the FPA and section 39.5(f) of our regulations, the Commission directs the 

ERO to develop modifications to MOD-001-1 pursuant to the ERO’s Reliability 

Standards development process to prevent the double-counting of data inputs and 

assumptions. In developing these modifications, the ERO should consider the effects of 

conditional firm service. 

 104 Standards for Business Practices and Communication Protocols for Public 

Utilities, Order No. 676-E, 129 FERC ¶ 61,162. 
Docket No. RM08-19-000, et al. - 111 - 

f. MOD-001-1, Requirement R2

NOPR Proposal

185. In the NOPR, the Commission proposed to approve MOD-001-1, including 

Requirement R2. Requirement R2 states that “Each Transmission Service Provider shall 

calculate [available transfer capability] or [available flowgate capability] values as listed 

below using the methodologies selected by its Transmission Operator(s).” A 

transmission service provider must calculate these values according to the following subrequirements: R2.1 “Hourly values for at least the next 48 hours;” R2.2 “Daily values for 

at least the next 31 days;” and R2.3 states “Monthly values for at least the next 12 

months.” 

Comment

186. Entergy requests clarification of the available transfer capability/available 

flowgate capability calculations that must be performed under Requirement R2 of MOD001-1. Entergy states that it is unclear whether these sub-requirements dictate a 

minimum level of granularity in calculated available flowgate capability values and 

whether the sub-requirements overlap each other or are independent requirements. As an 

example, Entergy states that a transmission operator that calculates hourly values for the 

next 48 hours, under these sub-requirements, should meet the requirement and not be 

required to also calculate two, separate daily values for the time period captured by those 

hours. Thus, Entergy contends, the hourly values should be sufficient, in this example, to 

comply with the Reliability Standard without calculating any additional daily values. 
Docket No. RM08-19-000, et al. - 112 - 

187. Similarly, Entergy states that it is unclear whether, in addition to the calculation of 

daily available transfer capability values over the next 31 days, the transmission operator 

must also calculate monthly available flowgate capability values for the same period, or 

whether the transmission operator may simply calculate the daily values for the 31 days 

in the first month and then calculate monthly values for the remaining eleven months in 

the “the next 12 months” period. Entergy states that it believes that this is the intent of 

the requirements because of the use of the word “next” in Requirements R2.1, R2.2 and 

R2.3 as well as the parenthetical “(months 2-13)” in Requirement R2.3. 

188. Entegra asks the Commission to direct the ERO to modify Requirement R2 to 

require transmission service providers to eliminate or minimize the use of inconsistent 

modeling practices over different timeframes. Entegra contends that if a transmission 

service provider determines that it is not feasible to use consistent modeling practices for 

all timeframes, the revised standard should require transmission service providers to 

identify and document differences in models and modeling practices due to available 

transfer capability/available flowgate capability calculation timeframes and provide a 

justification for each of the various modeling practices employed. 

189. Entegra also asks the Commission to direct the ERO to modify Requirement R2.3 

to clarify that transmission service providers that currently post available transfer 

capability or available flowgate capability values for a longer period should continue to 
Docket No. RM08-19-000, et al. - 113 - 

do so. Entegra contends that failing to direct such a revision would allow the ERO to 

adopt a lowest common denominator rule in violation of Order No. 672.105 

Commission Determination

190. Under Requirement R2 of MOD-001-1, transmission service providers must 

calculate hourly, daily and monthly values for available transfer capability or available 

flowgate capability. The requirement also sets a minimum frequency for such 

calculations. For example, a transmission service provider must calculate available 

transfer capability or available flowgate capability hourly for at least the next 48 hours. 

However, a transmission service provider calculating these values for a longer period 

would comply with the Reliability Standard. Thus, we reject the notion Requirement R2 

represents the “lowest common denominator.” 

191. To the extent necessary, we clarify that the timeframes for calculating available 

transfer capability and available flowgate capability are not concurrent. A transmission 

service provider must calculate hourly values for the next 48 hours. Beyond those 48 

hours, the transmission service provider must calculate daily values for at least the next 

31 calendar days. And, beyond those 31 calendar days, a transmission service provider 

must calculate monthly values for at least the next 12 months (months 2-13). This 

understanding is supported by the fact that the ERO describes each period as the “next” 

period and the next 12 months as months 2 through 13. 

 105 Citing Order No. 672, FERC Stats. & Regs. ¶ 31,204 at P 329. 
Docket No. RM08-19-000, et al. - 114 - 

192. In its filing letter, NERC states that it requires applicable entities to calculate 

available transfer capability or available flowgate capability on a consistent schedule and 

for specific timeframes. In keeping with the Commission’s goals of consistency and 

transparency in the calculation of available transfer capability or available flowgate 

capability, the Commission finds that transmission service providers should use 

consistent modeling practices over different timeframes. If a transmission service 

provider uses inconsistent modeling practices over different timeframes, that should be 

made explicit in its implementation document along with a justification for the 

inconsistent practices. Accordingly, pursuant to section 215(d)(5) of the FPA and section 

39.5(f) of our regulations, the Commission directs the ERO to develop a modification to 

the Reliability Standard pursuant to its Reliability Standards development process 

requiring transmission service providers to include in their implementation documents 

any inconsistent modeling practices along with a justification for such inconsistencies. 

g. MOD-001-1, Requirement R3

NOPR Proposal

193. In the NOPR, the Commission proposed to approve MOD-001-1, including 

Requirement R3, which requires transmission service providers to prepare and keep a 

current available transfer capability implementation document. Sub-requirement R3.5 

requires the transmission service provider to include in the implementation document a 

description of the allocation processes used to allocate transfer or flowgate capability: 

(1) among multiple lines or sub-paths within a larger available transfer capability path or 
Docket No. RM08-19-000, et al. - 115 - 

flowgate; (2) among multiple owners or users of an available transfer capability path or 

flowgate; and (3) between transmission service providers to address issues such as 

forward looking congestion management and seams coordination. 

Comment

194. Entergy requests that the Commission direct NERC to clarify that the applicability 

of these requirements is not triggered merely by participation in a seams agreement, but 

by the transmission service provider’s participation in a seams agreement that also 

provides for a forward-looking congestion management process between one or more 

transmission service providers. Entergy states that some transmission service providers 

may be parties to seams agreements that do not address a forward-looking congestion 

management process or the allocation of flowgate capabilities among multiple owners or 

users. Under such circumstances, Entergy contends that the purposes of sub-requirement 

R3.5 would not be serviced by setting forth the details of such agreement in the available 

transfer capability implementation document. 

Commission Determination

195. The Commission believes that Requirement R3 is sufficiently clear without 

making any distinction as to what sort of seams agreements or other type of agreement 

may be in place. If a seams agreement does not consider forward-looking congestion 

management or allocation of flowgate capabilities among multiple owners or users, the 

information posted under this requirement should so reflect. Participation in a seams 
Docket No. RM08-19-000, et al. - 116 - 

agreement does not excuse a transmission service provider from complying with this 

requirement. 

h. MOD-001-1, Requirements R6 and R7

NOPR Proposal

196. In the NOPR, the Commission proposed to approve MOD-001-1, including 

Requirements R6 and R7. Requirement R6 requires transmission operators calculating 

total transfer capability or total flowgate capability to use assumptions no more limiting 

than those used in the planning of operations for the corresponding time period studied, 

providing such planning of operations has been performed for that period. Similarly, 

Requirement R7 requires transmission service providers calculating available transfer 

capability or available flowgate capability to use assumptions no more limiting than those 

used in the planning of operations for the corresponding time period studied, providing 

such planning of operations has been performed for that period. 

Comment

197. Entergy points out that, in Order No. 890, the Commission stated that it would 

adopt its “NOPR proposal to require transmission providers to use data and modeling 

assumptions for the short- and long-term available transfer capability calculations that are 

consistent with that used for the planning of operations and system expansion, 

respectively, to the maximum extent possible.”106 Entergy also points out that, in Order 

 106 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 292. 
Docket No. RM08-19-000, et al. - 117 - 

 

No. 693, the Commission stated that the process and criteria “used to determine transfer 

capabilities must be consistent with the process and criteria used for other users of the 

Bulk-Power System.”107 Entergy states that, as currently drafted, Requirements R6 and 

R7 do not specifically define “planning of operations.” Entergy also states that the 

phrase “for the corresponding time period studied, providing such planning of operations 

has been performed for that period” is unclear, making it difficult to determine the 

assumptions that may not be more limiting. Accordingly, Entergy asks the Commission 

to direct NERC to modify MOD-001-1, Requirements R6 and R7 to explicitly state 

whether the assumptions used for long-term planning, i.e. the assumptions used to plan 

for native load and reliability, can be no more limiting than the assumptions used to 

calculate available transfer capability or available flowgate capability and total transfer 

capability or total flowgate capability. 

198. Entegra contends that the proposed Reliability Standard would permit 

transmission service providers to use a wide range of assumptions for available flowgate 

capability and total transfer capability or total flowgate capability calculations, which 

need not be consistent with those calculations used for different time periods, much less 

with the assumptions used for the planning of operations or system operations. 

Accordingly, Entegra asks the Commission to direct the ERO to revise MOD-001-1 to 

require transmission service providers to use data and assumptions for their short-term 

107 Citing Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 758. 
Docket No. RM08-19-000, et al. - 118 - 

 

and long-term available transfer capability or available flowgate capability and total 

transfer capability or total flowgate capability calculations that are consistent with (i.e., 

the same as) those used in the planning of operations and system expansion, respectively, 

to the maximum extent possible, as required by Order Nos. 693 and 890.108 In addition, 

Entegra asks the Commission to direct the ERO to revise the requirements to explicitly 

require all transmission service providers to incorporate all data, modeling assumptions, 

and mitigation procedures used in operations planning and long-term expansion studies in 

their available flowgate capability and total transfer capability or total flowgate capability 

models and calculations. 

199. Midwest ISO contends that the terms “assumptions” and “no more limiting” as 

used in Requirements R6 and R7 are not specific enough for entities to prepare for 

compliance. Midwest ISO states, for example, that it is unclear whether load assumption 

falls within the scope of “assumption” and, if so, which load assumption is deemed to be 

“more limiting” than another. Accordingly, Midwest ISO asks the Commission to direct 

the ERO to provide more specific details about what constitutes an “assumption” and to 

define the scope of the phrase “no more limiting” so that the Reliability Standard may be 

followed and audited with greater specificity. 

108 Citing Id. P 1057; Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 292. 
Docket No. RM08-19-000, et al. - 119 - 

Commission Determination

200. With regard to Midwest ISO’s concern, while the terms “assumptions” and “no 

more limiting” as used in Requirements R6 and R7 could benefit from further granularity, 

we find these Requirements to be sufficiently clear for purposes of compliance. 

Likewise, with regard to Entegra’s concern, we agree that transmission service providers 

should use data and assumptions for their available transfer capability or available 

flowgate capability and total transfer capability or total flowgate capability calculations 

that are consistent with those used in the planning of operations and system expansion. 

Under Requirements R6 and R7, transmission service providers and transmission 

operators must not overstate assumptions that are used in planning of operations. We 

believe these requirements are sufficiently clear as written. Nonetheless, we encourage 

the ERO to consider Midwest ISO’s and Entegra’s comments when developing other 

modifications to the MOD Reliability Standards pursuant to the ERO’s Reliability 

Standards development procedure. 

201. While Entergy is correct that the Standard does not define “planning of 

operations,” we do not find either that phrase or the phrase “for the corresponding time 

period studied, providing such planning of operations has been performed for that period” 

unclear. It is not necessary for this Reliability Standard to make an explicit statement 

about the assumptions used in long-term planning. 
Docket No. RM08-19-000, et al. - 120 - 

i. MOD-001-1, Requirement R9

NOPR Proposal

202. In the NOPR, the Commission proposed to approve MOD-001-1, including 

Requirement R9, which provides that “[w]ithin thirty calendar days of receiving a request 

by any Transmission Service Provider, Planning Coordinator, Reliability Coordinator, or 

Transmission Operator for data ... solely for the use in the requestor’s [available transfer 

capability] or [available flowgate capability] calculations, each transmission service 

provider receiving said request shall begin to make the requested data available to the 

requestor, subject to the conditions specified in R9.1 and R9.2.” Sub-requirement R9.2 

provides that “[t]his data shall be made available by the Transmission Provider on the 

schedule specified by the requestor (but no more frequently than once per hour, unless 

mutually agreed to by the requestor and the provider).” 

Comments

203. Entergy asks NERC to clarify that, while the transmission provider must make the 

requested data available to the requestor according to the schedule specified by the 

requestor, the transmission provider is not obligated to provide the data on a more 

frequent basis than the transmission provider updates its available flowgate capability 

models. Entergy contends that this clarification would make sub-requirement R9.2 

consistent with the apparent purpose of sub-requirement R9.1, which seeks to minimize 

the burden on the transmission service provider by requiring the transmission service 
Docket No. RM08-19-000, et al. - 121 - 

provider to make the data available to a requestor in the format maintained by the 

transmission service provider. 

204. Entergy states that the Reliability Standard does not require the exchange of data 

regarding counterflows and available transfer capability recalculation frequency and 

timing, as required by Order No. 890.109 Entergy asks the Commission to direct the ERO 

to modify Requirement R9 to require transmission service providers to exchange such 

information. In addition, Entergy contends that the Reliability Standard should be 

revised to mandate periodic exchange of all model data and on-going coordination of 

available flowgate capability and total transfer capability or total flowgate data among 

adjacent transmission service providers, rather than only requiring such data exchange 

upon the request of a limited class of users of the Bulk-Power System. 

Commission Determination

205. The Commission finds that, under Requirement R9 of MOD-001-1, a transmission 

service provider must respond to requests for data even when they are made more 

frequently than the transmission service provider updates its available transfer or 

flowgate capability models. If a request is made before the transmission service provider 

has updated its model, the transmission service provider must respond providing the same 

data as previously produced or making a statement that no change has been made. The 

Commission does not foresee this requirement as becoming a burden because a requestor 

 109 Citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 310. 
Docket No. RM08-19-000, et al. - 122 - 

 

is not likely to request more often than the calculation frequency if they are aware of the 

frequency with which the value is updated. Additionally, Requirement R9.2 addresses a 

maximum frequency for which any entity can request a given available transfer capability 

or flowgate value. For these reasons, the Commission will not direct the proposed 

modifications. 

206. In response to Entergy’s concern, the Commission believes that Requirement R9 is 

sufficiently clear insofar as it requires the exchange of data regarding counterflows and 

available transfer capability recalculation frequency and timing, as required by Order 

No. 890.110 Requirement R9, requires transmission service providers to provide available 

transfer capability values for all available transfer capability paths. These values should 

include information on counterflows because, under Requirement R3.2 of MOD-001-1, a 

transmission service provider must include in its implementation documents a description 

of how it accounts for counterflows. Moreover, under Requirement R9.1, a transmission 

service provider must make its own data available for up to 13 months after receiving a 

request for data. 

110 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 310. The Commission 

found that the following data shall, at a minimum be exchanged among transmission 

providers for the purposes of available transfer capability modeling: (1) load levels; 

(2) transmission planned and contingency outages; (3) generation planned and 

contingency outages; (4) base generation dispatch; (5) exiting transmission reservations, 

including counterflows; (6) available transfer capability recalculation frequency and 

times; and (7) source/sink modeling identification. 
Docket No. RM08-19-000, et al. - 123 - 

j. MOD-001-1, Counterflows

NOPR Proposal

207. In the NOPR, the Commission reiterated its concern from Order No. 890 regarding 

consistency in the use of counterflow assumptions in short-term and long-term 

calculations of available transfer capability.111 The Commission noted, in the NOPR, 

that the MOD Reliability Standards achieve consistency by requiring each transmiss

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. 

ion 

 

208. Requirement R3.2 of MOD-001-1 requires a transmission service provider to 

include in its available transfer or flowgate capability implementation document a 

description of the manner in which the transmission service provider will account for 

counterflows. The Commission expressed concern, however, that the Reliability 

Standards place no limit on the parameters the transmission service provider can use to 

account for counterflows. Accordingly, the Commission proposed to direct a review of 

the additional parameters and assumptions included by each transmission service 

provider in its implementation document and sought comment on whether additional 

111 NOPR, FERC Stats. & Regs. ¶ 32,641 at P 91; Order No. 890, FERC Stats. & 

Regs. ¶ 31,241 at P 292-93; Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1039. 
Docket No. RM08-19-000, et al. - 124 - 

requirements should be directed to eliminate the potential for undue discrimination in the 

provision of transmission service. 

Comments

209. Entegra contends that the Commission should direct the ERO to modify 

Requirement R3.2 of MOD-001-1 to ensure that counterflows are modeled consistently 

and to require transmission service providers to provide a justification, along with work 

papers and analyses, for the counterflow percentage used in their calculations of firm and 

non-firm available transfer capability or available flowgate capability. Entegra contends 

that the Reliability Standard should also require each transmission service provider to 

measure and account for counterflows in a manner that reflects actual operations and 

system conditions. Accordingly, Entegra suggests that the Reliability Standard should 

require transmission service providers to benchmark the treatment of counterflows 

against actual events and to update the models and counterflow methodology. Entegra 

also suggests that the MOD-001-1 should require transmission service providers to adopt 

a methodology that will not restrict competition or result in unduly discriminatory 

treatment. 

Commission Determination

210. As discussed above, the benchmarking of available transfer capability and 

available flowgate capability values and their components will provide information 

necessary to determine whether the calculations are being performed in a consistent 

manner. The audit of sub-requirement R3.1 directed above will address all parameters 
Docket No. RM08-19-000, et al. - 125 - 

used to calculate available transfer capability or available flowgate capability that are 

necessary to validate the calculations. Furthermore, transmission service providers 

within the Commission’s jurisdiction under section 205 of the FPA are already required 

to not adopt a methodology that will restrict competition or result in unduly 

discriminatory treatment. For these reasons, Entegra’s suggested modifications of subrequirement R3.2 are not necessary at this time. 

2. MOD-004-1, Capacity Benefit Margin

NOPR Proposal

211. 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 that 

reflect 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/or (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, 
Docket No. RM08-19-000, et al. - 126 - 

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. 

212. In the NOPR, the Commission expressed concern 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. The Commission explained that, 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 Commission observed that 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 therefore proposed, 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. 
Docket No. RM08-19-000, et al. - 127 - 

213. The Commission also expressed concern regarding references to applicable 

reserve margin and resource adequacy requirements in the determination of the 

generation capability import requirements by load-serving entities and resource planners 

under Requirements R3.1 and R4.1. The Commission stated that, 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, the Commission 

commented, 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, the Commission observed that 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 therefore proposed, 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. 
Docket No. RM08-19-000, et al. - 128 - 

Comments

214. NERC objects to the Commission’s proposed modification to MOD-004-1. To 

address a perceived disparity in MOD-004-1, NERC explains that, based on stakeholder 

guidance, it determined that the actual manner in which a load-serving entity or resource 

planner determines its generation capability import requirement may differ significantly 

based on the requestor’s internal practices, as well as the regulatory regime under which 

it operates. NERC states that the use of the words “one or more” in the Reliability 

Standard was intended to indicate that an entity desiring to have capacity benefit margin 

withheld for its potential use could establish that need using any one of the methods 

described. NERC states that the entity also has the option to provide additional studies or 

information if it so desired or was obligated to do so. In the case of a transmission 

service provider or transmission planner, however, NERC states that the Reliability 

Standard drafting team felt that it was important that any information provided be 

considered when establishing an appropriate level of capacity benefit margin. 

215. Georgia Companies contend that a transmission service provider cannot ensure 

that the calculation of capacity benefit margin would not impair the reliable operation of 

the Bulk-Power System because that would require ensuring resource adequacy, which a 

transmission service provider cannot do. Georgia Companies state that a transmission 

service provider must rely on resource adequacy information provided by load serving 

entities when managing transmission reliability. Therefore, Georgia Companies contend 
Docket No. RM08-19-000, et al. - 129 - 

that the Commission should accept the NERC-proposed language in MOD-004-1 that 

transmission providers reflect consideration of any studies received from customers. 

216. Georgia Companies also state that, on its surface, it appears that MOD-004-1 

appears inconsistent by allowing a load serving entity or resource planner to perform one 

or more of the listed options while requiring a transmission service provider or 

transmission planner to use all options. Nevertheless, Georgia Companies contend that 

the requirements are accurate and consistent as written because the relevant studies are 

not applicable in all regions. Thus, Georgia Companies ask the Commission to not 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. If the 

Commission does direct such action, Georgia Companies contend that it could require a 

load serving entity or resource planner to perform studies that are not required (nor 

applicable or used) by multiple state agencies, RTOs, ISOs, or other regional authorities. 

217. Midwest ISO expresses concern that the Reliability Standards drafting team 

interpreted the language from Order Nos. 890 and 693 such that a load serving entity’s 

request to set aside capacity benefit margin is final, and that no input is permitted by the 

transmission service provider, even if the load serving entity is part of an ISO or RTO. 

Midwest ISO contends that this interpretation could result in an unreasonable overreservation of capacity benefit margin, considering the scant likelihood of actual 

impairment of the reliability of the system. Midwest ISO contends that the benefit to 
Docket No. RM08-19-000, et al. - 130 - 

system reliability that would result from setting aside capacity benefit margin for a lowprobability scenario is outweighed by the complexity of compliance with an inflexible 

interpretation of the Commission’s orders. Thus, Midwest ISO asks the Commission to 

direct the ERO to consider the transmission service provider’s role in assessing the total 

amount of capacity benefit margin reasonably required to preserve the reliability of the 

system. 

218. TAPS supports the Commission’s proposal to direct the ERO to develop 

modifications to the Reliability Standard that require capacity benefit margin set-asides to 

determine generation capability import requirements by reference to relevant studies and 

applicable reserve margin or resource adequacy requirements, as relevant. TAPS 

expresses concern, however, that the NOPR proposal could be interpreted as requiring 

load-serving entities and resource planners to perform such assessments even if they are 

not requesting that transmission be set aside for capacity benefit margin. Accordingly, 

TAPS asks the Commission to clarify that Requirements R3 and R4 of MOD-004-1 

require performance assessments only by those load-serving entities and resource 

planners that are requesting capacity benefit margin to be set aside. 

219. The ITC Companies also support the Commission’s proposed modification to 

MOD-004-1. The ITC Companies state that they agree with the Commission that the 

requirement that the transmission service provider is to “reflect consideration” of studies 

provided by the load serving entity or resource planning in establishing the capacity 

benefit margin under MOD-004-1 is not specific enough and results in an unbounded 
Docket No. RM08-19-000, et al. - 131 - 

requirement. The ITC Companies contend that it is not a burdensome request for the 

load-serving entity or resource planner to provide a detailed study to support the 

generator capability import requirement used in setting the capacity benefit margin. 

Commission Determination

220. We agree with NERC that a transmission service provider should consider any 

information provided in establishing an appropriate level of capacity benefit margin. 

Similarly, we agree with the Georgia Companies that all relevant information should be 

considered in establishing an appropriate level of capacity benefit margin, including 

information provided by customers. However, in determining the appropriate generation 

capacity import requirement as part of the sum of capacity benefit margin to be requested 

from the transmission service provider, it would not be appropriate for a load-serving 

entity or resource planner to rely exclusively on a reserve margin or adequacy 

requirement established by an entity that is not subject to this Standard. Thus, we hereby 

adopt the NOPR proposal to direct the ERO to develop a modification to Requirements 

R3.1 and R.4.1 of MOD-004-1 to require load-serving entities and resource planners to 

determine generation capability import requirements by reference to one or more relevant 

studies (loss of load expectation, loss of load probability or deterministic risk analysis) 

and applicable reserve margin or resource adequacy requirements, as relevant. Such a 

modification should ensure that a transmission service provider has adequate information 

to establish the appropriate level of capacity benefit margin. 
Docket No. RM08-19-000, et al. - 132 - 

221. In response to TAPS concerns, we believe that the Reliability Standard is 

sufficiently clear that load-serving entities and resource planners who do not request 

capacity benefit margin be set aside are not required to perform the studies prescribed in 

MOD-004-1. Requirements R3 and R4 require load-serving entities and resource 

planners determining the need for transmission capacity to be set aside as capacity benefit 

margin for imports into balancing authority to use certain studies. Thus, if a load-serving 

entity or resource planner is not determining such a need because it chooses not to 

request capacity benefit margin to be set aside, there is no obligation to use the studies 

listed in Requirements R3.1 and R4.1. Moreover, the requirement is to “use” the listed 

studies. Thus, a load-serving entity or resource planner could use a study that has been 

conducted by another entity, such as an ISO or RTO. 

222. We agree with the Midwest ISO that ISOs, RTOs, and other entities with a wide 

view of system reliability needs should be able to provide input into determining the total 

amount of capacity benefit margin required to preserve the reliability of the system. 

However, Requirements R1.3 and R7 already make clear that determinations of need for 

generation capability import requirement made by a load serving entity or resource 

planner are not final. Further, the third bullet of Requirements R5 and R6 explicitly lists 

reserve margin or resource adequacy requirements established by RTOs and ISOs among 

the factors to be considered in establishing capacity benefit margin values for available 

transfer capability paths or flowgates used in available transfer capability or available 

flowgate capability calculations. In fact, it is for this reason that we uphold the NOPR 
Docket No. RM08-19-000, et al. - 133 - 

proposal. Therefore, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of our 

regulations, the Commission directs the ERO to modify MOD-004-1 to clarify the term 

“manage” in Requirement R1.3. This modification should ensure that the Reliability 

Standard clarify how the transmission service provider will manage situations where the 

requested use of capacity benefit margin exceeds the capacity benefit margin available. 

3. MOD-008-1, Transfer Reliability Margin

NOPR Proposal

223. In the NOPR, the Commission proposed to approve Reliability Standard MOD008-1 without modification. 

Comments

224. Entegra states that the Reliability Standard does not establish a maximum 

transmission reserve margin, as required by Order No. 890. Entegra states that the 

Reliability Standard gives transmission operators unbounded discretion to adopt whatever 

transmission reserve margin they choose, without placing any substantive limits on 

parameters, modeling requirements, criteria, or assumptions used to calculate the 

transmission reserve margin. Accordingly, Entegra asks the Commission to direct the 

ERO to establish a maximum transmission reserve margin. Entegra points out that the 

Commission found, in Order No. 890, that the “percentage of ratings reduction” method 

is a reasonable method because it is relatively simple to apply and does not restrict 

transmission operators from using a more sophisticated method if appropriate. 
Docket No. RM08-19-000, et al. - 134 - 

Commission Determination

225. The Commission will not direct that a maximum transmission reserve margin be 

established here. Although the Commission previously stated that the “percentage of 

ratings reduction” method is reasonable, the Commission does not believe that it is 

necessary to fix a maximum value or percentage of transfer capability set aside as 

transmission reserve margin. As stated above, the Commission believes that it is 

appropriate for transmission service providers to retain some level of discretion. We 

believe that transmission service providers should retain the discretion to manage risks 

associated with their particular system configurations and physical limitations. 

Nonetheless, we believe that it would be inappropriate for a transmission service provider 

to set transmission reserve margin excessively and unjustifiably high. The transparency 

set by these MOD Reliability Standards will allow the Commission, NERC and other to 

monitor transmission reserve margin values to determine if they are reasonable and 

internally consistent. The Commission will evaluate evidence of excessive transmission 

reserve margins on a case-by-case basis as reports of any such occurrences arise. The 

Commission, therefore, declines to direct the proposed modification to MOD-008-1. 

4. MOD-028-1, Area Interchange Methodology

226. In the NOPR, the Commission proposed to approve Reliability Standard 

MOD-028-1 without modification. 
Docket No. RM08-19-000, et al. - 135 - 

a. General

Comments

227. FPL points out that the introduction to MOD-028-1 provides that the area 

interchange methodology is characterized by determination of incremental transfer 

capability via simulation, from which total transfer capability can be mathematically 

derived. FPL contends that mathematical derivation of total transfer capability is overly 

simplistic for implementation. FPL explains that the simple mathematical additions and 

subtractions ignore the interactions between existing commitments going between 

different balancing authorities as well as the different distribution factors that various 

existing commitments may have on different flow gates. 

Commission Determination

228. FPL did not adequately explain its concern about the mathematics required to 

derive total transfer capability. The Commission does not intend to force any party to 

implement an unrealistically simplistic methodology, and notes that Requirement R1 

provides parties using the area interchange methodology the latitude to specify the 

manner of computation necessary to allow other parties to validate the computation. 

b. MOD-028-1, Requirement R2

NOPR Proposal

229. In the NOPR, the Commission proposed to approve MOD-028-1, including 

Requirement R2, which provides that, when calculating total transfer capability for 

available transfer capability paths, transmission operators must use a transmission model 
Docket No. RM08-19-000, et al. - 136 - 

that contains modeling data and topology of its reliability coordinator’s area of 

responsibility, modeling data and topology (or equivalent representation) for immediately 

adjacent and beyond reliability coordination areas, and facility ratings specified by the 

generator owners and transmission owners. 

Comments

230. FPL points out that sub-requirement R2.2 requires the use of “modeling data and 

topology (or equivalent representation) for immediately adjacent and beyond Reliability 

Coordination areas.” FPL contends that the term “beyond” is vague and subject to 

different interpretation. Accordingly, FPL asks the Commission to direct the ERO to 

address this ambiguity. 

Commission Determination

231. The Commission understands sub-requirement R2.2 of MOD-028-1 to mean that, 

when calculating total transfer capability for available transfer capability paths, a 

transmission operator shall use a transmission model that includes relevant data from 

reliability coordination areas that are not adjacent. While we believe that the provision is 

reasonably clear, the Commission agrees that the term “and beyond” could be better 

explained. Accordingly, pursuant to section 215(d)(5) of the FPA and section 39.5(f) of 

our regulations, the Commission directs the ERO to develop a modification subrequirement R2.2 pursuant to its Reliability Standards development process to clarify the 

phrase “adjacent and beyond Reliability Coordination areas.” 
Docket No. RM08-19-000, et al. - 137 - 

c. MOD-028-1, Requirement R5

NOPR Proposal

232. In the NOPR, the Commission proposed to approve MOD-028-1 including 

Requirement R5, which requires transmission operators to establish total transfer 

capability for each available transfer capability path according to the following schedule: 

(1) at least once within the seven calendar days prior to the specified period for total 

transfer capabilities used in hourly and daily available transfer capability calculations; 

(2) at least once per calendar month for total transfer capabilities used in monthly 

available transfer capability calculations; and (3) within 24 hours of the unexpected 

outage of a 500 kV or higher transmission facility or transformer with a low-side voltage 

of 200 kV or higher for total transfer capabilities in effect during the anticipated duration 

of the outage, provided such outage is expected to last 24 hours or longer. 

Comment

233. FPL comments that sub-requirement R5.2 provides that that total transfer 

capability be established “[w]ithin 24 hours of the unexpected outage of a 500 kV or 

higher transmission Facility or transformer with a low-side of 200 kV or higher for [total 

transfer capabilities] in effect during the anticipated duration of the outage.” FPL 

contends that this sub-requirement is too restrictive and burdensome in certain situations. 

As an example, FPL states that meeting this requirement will be difficult if a facility is 

expected to be out of service for an extended time frame, e.g., a catastrophic transformer 

failure which could take a year to replace. FPL asks the Commission to consider a 
Docket No. RM08-19-000, et al. - 138 - 

graduated time frame for reposting where hourly data for the next 168 hours would be 

reposted within 24 hours; the following 23 days of daily data would be reposted within 

48 hours; and, the 13 months of monthly data would be reposted within five working 

days. FPL contends that this would allow time for the extent of the damage to be 

determined and proper assessments of replacement times to be established. 

Commission Determination

234. The Commission believes that, as written, the time frames established in 

Requirement R5 are just and reasonable because they balance the need to reliably operate 

the grid with the burden on transmission operators to recalculate total transfer capability 

even when total transfer capability does not often change. Nevertheless, the Commission 

agrees that a graduated time frame for reposting could be reasonable in some situations. 

Accordingly, the ERO should consider this suggestion when making future modifications 

to the Reliability Standards. 

d. MOD-028-1, Requirement R6

NOPR Proposal

235. Requirement R6 of MOD-028-1 requires transmission service providers to 

establish total transfer capability for each available transfer capability path by use of 

process specified in the sub-requirements. Requirement R6.1 requires transmission 

operators to determine the incremental transfer capability for each available transfer 

capability path by increasing generation and/or decreasing load within the source 

balancing authority area and decreasing generation and/or increasing load within the 
Docket No. RM08-19-000, et al. - 139 - 

balancing authority area until either: a system operating limit is reached on the 

transmission service provider’s system or a system operating limit is reached on any 

other adjacent system in the transmission model that is not on the study path and the 

distribution factor is 5 percent or greater. 

Comments

236. Regarding sub-requirement R6.1, FPL contends that the 5 percent or less 

distribution factor should apply regardless of whether the limitation is on the study path 

or on an adjacent system. FPL contends that allowing application of the 5 percent 

distribution factor only on adjacent systems will create confusion and will cause 

inconsistent available transfer capability postings depending on who is calculating the 

path. FPL also points out that the footnote for sub-requirement R6.1 states that a 

distribution factor applied in R6.1 can be less than 5 percent. FPL contends that the once 

a distribution factor is selected it should be applied for all paths so that there is not a 

different distribution factor for different paths. FPL further contends that the distribution 

factor to be used should be clearly stated in the available transfer capability 

implementation document. 

Commission Determination

237. The Commission agrees that any distribution factor to be used should be clearly 

stated in the implementation document, and that to facilitate consistent and 

understandable results the distribution factors used in determining total transfer capability 

should be applied consistently. Accordingly, pursuant to section 215(d)(5) of the FPA 
Docket No. RM08-19-000, et al. - 140 - 

and section 39.5(f) of our regulations, the Commission directs the ERO to develop a 

modification to MOD-028-1 pursuant to its Reliability Standards development process to 

address these two concerns. 

5. MOD-029-1, Rated System Path Methodology

a. Sub-Requirement R2.7

NOPR Proposal

238. In the NOPR, the Commission stated that NERC failed to explain, and it was not 

clear why certain applicable entities would be required to use pre-1994 total transfer 

capability values under sub-requirement R2.7 in the Rated System Path Methodology. 

The Commission expressed concern 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 incorrectly based on stale 

assumptions and data. Accordingly, the Commission sought comment on whether it 

should direct the ERO to develop a modification to the Rated System Path Methodology 

(MOD-029-1) to remove sub-requirement R2.7 as unsupported. 
Docket No. RM08-19-000, et al. - 141 - 

Comments

239. Many commenters contend that the Commission should retain sub-requirement 

R2.7 of MOD-029-1.112 Some urge the Commission to give due weight to the technical 

expertise of the ERO with respect to the inclusion of sub-requirement R2.7.113 

Commenters explain that the path-rating methodology in MOD-029-1 represents the 

current methodology for calculating available transfer capability by entities operating 

within the area of the Western Electricity Coordinating Council (WECC). They contend 

that although these values can be based on pre-1994 total transfer capability values, they 

must be updated seasonally within WECC and, thus, are not stale.114 

240. Northwestern claims that the basic premise of the WECC rating process is that 

new path ratings or a new rating for an upgraded path should not adversely impact the 

transfer capability of a path with either an accepted or existing rating. If a path’s transfer 

capability is adversely impacted, Northwestern states that the owners of the path seeking 

the rating would have to mitigate the impacts. Likewise, Pacific Northwest, Public 

Power Council and Snohomish state that the Existing Paths within WECC are reviewed 

 112 E.g., EEI, Northwestern, Northwest Utilities, LADWP, Avista, Modesto, 

Pacific Northwest, PacifiCorp, Puget Sound, SMUD, Salt River, SWAT, TANC and 

Tucson. 

113 E.g., EEI, Pacific Northwest, Public Power Council and SMUD. 

114 E.g., EEI, Northwestern, Northwest Utilities, LADWP, Avista, Modesto, 

Pacific Northwest, PacifiCorp, Puget Sound, SMUD, Salt River, SWAT, TANC and 

Tucson. 
Docket No. RM08-19-000, et al. - 142 - 

 

by the WECC Planning Committee and annually by the WECC Operating Committee to 

assign an appropriate system operating limit for each path. As such, they contend, the 

Existing path rating cannot yield total transfer capability or available transfer capability 

values in excess of the technically based seasonal system operating limit. SMUD notes 

that the industry has been using this system for fifteen years and, in that time, no one 

operating under these limits has filed any complaint, formal challenge, or request for a 

change. 

241. Some commenters argue that it would place extreme burden on WECC to re-rate 

all the paths in its path rating catalog that have an Existing Rating115 or Other 

designation; a total of 45 paths.116 Northwestern contends that requiring Existing Rating 

paths to go through some new process could seriously undermine the reliability and 

economic value the path owners have appropriately built into their long-range plan. 

Similarly, PacifiCorp argues that removal of sub-requirement R2.7 would hinder path 

ratings already in progress and negatively impact reliance on transmission rights because 

115 Existing Ratings are defined by WECC as transmission path ratings that were 

known and used in operation as of January 1, 1994. See, WECC, Overview of Policies 

and Procedures for Regional Planning Project Review, Project Rating Review, and 

Progress Reports (Revised April 2005), available at: 

http://www.wecc.biz/library/WECC%20Documents/Miscellaneous%20Operating%20and

%20Planning%20Policies%20and%20Procedures/Overview%20Policies%20Procedures

%20RegionalPlanning%20ProjectReview%20ProjectRating%20ProgressReports_07-

05.pdf. 

116 E.g., Modesto, Northwestern, Northwest Utilities, Nevada Companies, 

Pacificorp, and TANC. 
Docket No. RM08-19-000, et al. - 143 - 

 

many WECC path ratings are dependent upon parallel interactions and ratings with the 

parallel facilities owned by other transmission providers. Thus, PacifiCorp and 

Northwest Utilities contend, if sub-requirement R2.7 is removed, there will be likely be 

multiple contract disputes. Furthermore, if the Commission directs removal of 

requirement R2.7 from MOD-030-2, PacifiCorp contends that it will be impossible for 

entities to meet the one-year implementation schedule. Some commenters contend that 

the existing total transfer capabilities are operationally proven and that re-rating the paths 

within WECC would divert resources from higher reliability priorities for several years 

for no apparent reliability benefit.117 

242. By contrast, ISO/RTO Council supports the removal of sub-requirement R2.7. 

ISO/RTO Council states 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. 

To avoid continuance of or reversion to the pre-1994 total transfer capability value for a 

path under sub-requirement R2.7, ISO/RTO Council states that each RTO and ISO would 

be required to conduct comprehensive and time consuming studies of the paths they 

operate within a one-year period. ISO/RTO Council contends that it would be 

unreasonable to require that this level of effort in the absence of any explanation by 

117 E.g., Avista, LADWP, Modest, Salt River, SWAT, TANC, and Tucson. 
Docket No. RM08-19-000, et al. - 144 - 

NERC why such studies are necessary or what benefit it believes will result. 

Accordingly, ISO/RTO Council asks the Commission to direct the ERO to remove this 

sub-requirement. 

Commission Determination

243. The Commission approves Requirement R2.7 as proposed by NERC. As 

commenters note, although some total transfer capability values were developed for paths 

prior to 1994, WECC regularly reviews these paths to confirm that those values remain 

valid. Moreover, WECC requires re-rating of a Rated System path in a variety of 

instances.118 As a result, we find that commenters have provided sufficient evidence that 

the use of pre-1994 total transfer capability values for paths within WECC does not 

exempt those paths from the total transfer capability requirement in the Rated System 

Path Methodology. We are further satisfied that ratings for existing paths with pre-1994 

total transfer capability values are not incorrectly based on stale assumptions because the 

existing path ratings must be adjusted for seasonal variances. 

244. Although Requirement R2.7 appears to have been crafted to accommodate 

existing practices within WECC, the Commission points out that MOD-029-1 is a 

 118 See WECC, Overview of Polices and Procedures for Regional Planning Project 

Review, Project Rating Review, and Progress Reports (Revised April 2005), Sect. 2.3 

Paths Subject To This Procedure, available at: 

http://www.wecc.biz/library/WECC%20Documents/Miscellaneous%20Operating%20and

%20Planning%20Policies%20and%20Procedures/Overview%20Policies%20Procedures

%20RegionalPlanning%20ProjectReview%20ProjectRating%20ProgressReports_07-

05.pdf. 
Docket No. RM08-19-000, et al. - 145 - 

national Reliability Standard. Thus, the requirement is equally binding upon 

transmission operators and transmission service providers using the Rated System Path 

Methodology to calculate total transfer capabilities or available transfer capabilities for 

path outside of WECC. The Commission therefore clarifies that any transmission 

operator or transmission service provider operating outside of WECC that uses the Rated 

System Path Methodology must demonstrate to the ERO and the Commission a similar 

need to implement Requirement R2.7. 

b. Counterschedules

Comment

245. Puget Sound comments that counterflows are a mandatory component of the 

available transfer capability formula but contends that it is common practice in the 

Western Interconnection to incorporate counterschedules into non-firm available transfer 

capability calculations, instead of counterflows as defined in the formula. Puget Sound 

therefore requests that the Commission clarify in the Final Rule that using 

counterschedules will not be considered a violation of MOD-029-1. In addition, Puget 

Sound asks the Commission to clarify that counterflows and counterschedules are 

interchangeable terms, consistent with Western Interconnection practices. 

Commission Determination

246. Puget Sound’s request is reasonable, and insofar as calculating non-firm available 

transfer capability using counterschedules as opposed to counterflows achieves 

substantially equivalent results, using them will not be considered a violation. However, 
Docket No. RM08-19-000, et al. - 146 - 

we do not have enough information to determine that the terms are generally 

interchangeable in all circumstances. The ERO should consider Puget Sound’s concerns 

on this issue when making future modifications to the Reliability Standards. 

6. MOD-030-2, Flowgate Methodology

247. In the NOPR, the Commission proposed to approve MOD-030-2 without 

modification. Because MOD-030-2 wholly superseded MOD-030-1, NERC proposed to 

make the Reliability Standard effective on the same date upon which MOD-030-1 would 

have become effective. Thus, the Commission proposed to approve MOD-030-2 with an 

effective date set as the first day of the first quarter no sooner than one calendar year after 

approval of the Reliability Standard and its related three standards (MOD-001-1, MOD028-1, and MOD-29-1). 

a. MOD-030-2 Requirements R2.4 and R2.5

NOPR Proposal

248. In the NOPR, the Commission proposed to approve MOD-030-2, including subrequirements R2.4 and R2.5. Sub-requirement R2.4 provides that the transmission 

operator shall, at a minimum, establish the total flowgate capability of each of the defined 

flowgates as equal to: (1) for thermal limits, the system operating limit, of the flowgate; 

and (2) for voltage or stability limits, the flow that will respect the system operating limit 

of the flowgate. Sub-requirement R2.5 provides that the transmission operator shall, at a 

minimum, establish the total flowgate capability once per calendar year. 
Docket No. RM08-19-000, et al. - 147 - 

Comments

249. Entergy states that it interprets sub-requirements R2.4 and R2.5 as requiring an 

annual reevaluation to confirm the total flowgate capability of a defined flowgate is 

correctly set at the system operating limit of the flowgate based on thermal limits or the 

appropriate flow that will respect the system operating limit of the flowgate based on 

voltage or stability limits. Entergy contends that, when considered with sub-requirement 

R2.4, sub-requirement R2.5 could create confusions as to whether, as part of the annual 

“re-establishment” of the total flowgate capability, the transmission operators must first 

re-establish the system operating limit of each defined flowgate. Entergy states that the 

studies and tests that must be performed to establish the system operating limit of a set of 

transmission facilities typically require significant time and resources, and it is unlikely 

that they could be completed for all flowgates within one year. Accordingly, Entergy 

requests clarification that, as part of the annual establishment of the total flowgate 

capability of a flowgate, the transmission operator is not required to re-rate transmission 

facilities on an annual basis. 

Commission Determination

250. The Commission finds that, under sub-requirements R2.4 and R2.5, transmission 

operators are not required to update system operating limits of each flowgate when 

establishing the annual total flowgate capability. However, as per sub-requirement 

R2.5.1, the transmission operator should update the total flowgate capability within seven 

calendars days of the notification if it is notified of a change in the rating by the 
Docket No. RM08-19-000, et al. - 148 - 

transmission owner that would affect the total flowgate capability of a flowgate used in 

the available flowgate capability process. 

b. MOD-030-2 Requirements R3 and R10

NOPR Proposal

251. The Commission proposed, in the NOPR, to approve MOD-030-2 including 

Requirements R3 and R10. Requirement R3 requires the transmission operator to make 

available to the transmission service provider a transmission model to determine 

available flowgate capability that meets the criteria provided in the sub-requirements. 

Requirement R10, and its sub-requirements, provides that each transmission service 

provider shall recalculate available flowgate capability, utilizing the updated models 

described in sub-requirements R3.2, R3.3 and Requirement R5, at a minimum on the 

following frequency unless none of the calculated values identified in the available 

flowgate capability equation have changed: for hourly availability flowgate capability, 

once per hour; for daily availability flowgate capability, once per day; and for monthly 

availability flowgate capability, once per week. Sub-requirements R3.2 and R3.3 require 

that the transmission operator make available to the transmission service provider a 

transmission model for determination of availability flowgate capability that is: updated 

at least once per day for availability flowgate capability for intra-day, next day, and days 

two through thirty; and updated at least once per month for availability flowgate 

capability calculations for months two through thirteen. Requirement R5 addresses 

further requirements for data included in the models. 
Docket No. RM08-19-000, et al. - 149 - 

Comment

252. Entergy states that it understands sub-requirements R3.2 and R3.3 as establishing 

a requirement that the transmission model used by the transmission service provider must 

be updated, or re-solved, with a frequency of once a day and/or once per month, 

according to the applicable availability flowgate capability calculation. On the other 

hand, Entergy notes, Requirement R10 establishes requirements that the transmission 

service provider re-calculates availability flowgate capability by algebraically 

decrementing or incrementing availability flowgate capability values as appropriate, 

using the most recently updated transmission model on a more frequent basis. Entergy 

requests clarification that the transmission model used in the available flowgate 

capability calculations does not need to be updated more frequently than under the 

timelines set forth in sub-requirements R3.2 and R3.3, i.e., that the transmission model 

itself does not need to be updated according to the timelines in Requirement R10, which 

would only apply to the recalculation of availability flowgate capability values. 

Commission Determination

253. The Commission finds that sub-requirements R3.2 and R3.3 set the frequency by 

which the transmission model used in the available flowgate capability calculations needs 

to be updated. Transmission operators are not required to update the transmission model 

more frequently than prescribed in these sub-requirements. Under requirement R10, 

transmission service providers must use the transmission models provided by 

transmission operators to recalculate available flowgate capability on a more frequent 
Docket No. RM08-19-000, et al. - 150 - 

basis, i.e., hourly, once per hour; daily, once per day; and, monthly, once per week. A 

transmission service provider’s obligations under Requirement R10 should not require 

transmission operators to update transmission models any more frequently than required 

in sub-requirements R3.2 and R3.3. 

c. MOD-030-2 Existing Transmission Commitments, 

Requirement R6

NOPR Proposal

254. In the NOPR, the Commission proposed to approve MOD-030-2, including 

Requirement R6, which sets variables to use in calculating the impact of existing 

transmission commitments for firm commitments. These variables include: the impact 

of all firm network integration transmission service including native load and network 

service load, the impact of all confirmed firm point-to-point transmission service 

expected to be schedule including roll-over rights, the impact of any grandfathered firm 

obligation expected be scheduled, the impact of other firm services determined by the 

transmission service provider. Requirement R7 requires the transmission service 

provider to consider similar variables when calculating the impact of existing 

transmission commitments for non-firm commitments. 

Comments

255. Cottonwood states that, during the stakeholder process, it informed NERC that the 

existing transmission commitment calculation procedures in Requirement R6 were 

insufficiently detailed, and particularly failed to ensure that transmission service 
Docket No. RM08-19-000, et al. - 151 - 

providers do not overstate the capacity set aside for existing transmission commitments 

purposes. Although NERC responded that the responsible Reliability Standard drafting 

team has required the use of dispatch modeling information to determine these impacts, 

Cottonwood states NERC also clarified that the processes used to calculate existing 

transmission commitments should be included in the available transfer capability 

implementation documents. Cottonwood expresses concern that the NERC standards 

drafting team did not adequately address its concerns. 

256. Cottonwood contends that overstatement of existing transmission commitments is 

a serious problem for transmission customers because it understates the available transfer 

capability/available flowgate capability identified in the models, even though the system 

could actually carry additional service. Cottonwood further contends that overstatement 

of existing transmission commitments also can lead to the appearance of phantom 

congestion and base case overloads in the models, which effectively means that the 

existing transmission commitment impacts on certain flowgates is greater than the 

flowgates’ capacity, and, thus, these flowgates are overloaded in the available transfer 

capability power flow models, and access to the transmission system is reduced. To 

address these concerns, Cottonwood asks the Commission to direct the ERO to modify 

MOD-030-2 to include requirements that ensure that the generation dispatch model 

incorporates the way generating units actually are dispatched in daily operation, and any 

and all operating procedures used to maintain flows within limits. Cottonwood further 
Docket No. RM08-19-000, et al. - 152 - 

suggests that impacts from neighboring systems should be taken into account and 

properly modeled. 

257. Entegra contends that NERC’s proposal does not comply with the Commission’s 

directives in Order Nos. 693 and 890. Entegra states that the proposed existing 

transmission commitments calculation is loose and unclear and the proposed 

requirements do not prevent transmission service providers from overstating the flowgate 

capacity set aside for existing transmission purposes, which leads to base case 

contingency overloads. Accordingly, Entegra asks the Commission to direct the ERO to 

modify the Reliability Standard to require transmission providers to use an accurate and 

realistic dispatch model and to benchmark existing transmission commitment calculations 

against real-time flows to ensure that these values are not being overstated. In addition, 

Entegra contends that transmission service providers should be required to identify and 

report to NERC, on a periodic basis, all base case congestion overloads over five percent 

and chronic base case congestion overloads for further investigation and action. 

Commission Determination

258. In Order No. 890, the Commission determined that existing transmission 

commitments should be defined to include committed uses of the transmission system, 

including: (1) native load commitments (including network service); (2) grandfathered 

transmission rights; (3) appropriate point-to-point reservations; (4) rollover rights 

associated with long-term firm service; and (5) other uses identified through the NERC 
Docket No. RM08-19-000, et al. - 153 - 

 

process. 119 Further, the Commission decided that existing transmission commitments 

should not be used to set aside transfer capability for any type of planning or contingency 

reserve, which are instead addressed through capacity benefit margin and transfer 

reliability margin calculations.120 We find that, as written, the ERO’s definition of 

existing transmission capacity satisfies the Commission’s directions in Order No. 890. 

259. Under Requirements R6 and R7 of MOD-030-2, a transmission provider must sum 

the impact of certain defined transmission commitments as well as other firm and nonfirm services determined by the TSP. Relevant impact is undefined as are “other” firm 

and non-firm services. Thus, there is potential for a transmission service provider to 

overstate or understate existing transmission commitments. However, this concern is 

mitigated by fact that, under MOD-001-1 Requirement R2, transmission service 

providers must recalculate available transfer capability or available flowgate capability 

(which include existing transmission commitments) for specific time periods. Entities are 

also required to make their assumptions available. In addition, in measures M13 and 

M14 of MOD-030-2, NERC states that a recalculated existing transmission commitment 

value that is within 15 percent or 15 MW, whichever is greater, of the originally 

calculated values, is evidence that the transmission service provider used the 

119 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 244. 

120 Id.
Docket No. RM08-19-000, et al. - 154 - 

requirements defined in R6 and R7. We therefore decline to direct the modifications 

proposed. 

d. MOD-030-2 Power Transfer and Outage Transfer 

Distribution Factors

NOPR Proposal

260. Requirement R2 of MOD-030-2 provides that, in determining which flowgates to 

use in the available flowgate capability process the transmission operator must use, at a 

minimum, certain criteria as enumerated in the sub-requirements. Requirement R2.1.1 

requires transmission operators to consider the results of a first contingency transfer 

analysis from all adjacent balancing authority source and sink combinations up to the 

path capability such that at a minimum the first three limiting elements and their worst 

associated contingency combinations with an outage transfer distribution factor of at least 

5 percent and within the transmission operator’s system are included in the flowgates 

unless the interface between such adjacent balancing authorities is accounted for using 

another available transfer capability. Requirement R2.1.4 requires transmission operators 

to consider any limiting element or contingency where the coordination of the limiting 

element/contingency combination is not addressed through a different methodology, and, 

among other things, any generator within the transmission service provider’s area has at 

least a 5 percent power distribution factor or outage transfer distribution factor impact on 

the flowgate when delivered to the aggregate load of its own area. 
Docket No. RM08-19-000, et al. - 155 - 

Comments

261. Entegra states that NERC’s proposal gives transmission operators the discretion to 

use arbitrarily small distribution factors, without requiring any justification or 

explanation as to why the chosen value is appropriate. Entegra also states that the use of 

lower distribution factors may affect reliability insofar as it conflicts with other 

Reliability Standards, e.g., the transmission loading relief procedure, that uses a five 

percent distribution factor. Accordingly, Entegra asks the Commission to direct the ERO 

to modify the Reliability Standard to set a five percent default value for both the power 

transfer and outage transfer distribution factors. Entegra states that the revised Reliability 

Standard should require transmission operators to justify their choice of distribution 

factors if less than five percent. In addition, Entegra states that NERC should require 

transmission operators using a lower value to develop appropriate procedures to address 

any conflicts between the distribution factor values chosen for available transfer 

capability purposes and those used for other purposes, such as the transmission loading 

relief procedure. 

Commission Determination

262. In the NOPR, the Commission stated that it is appropriate for transmission service 

providers to retain some level of discretion in the calculation of available transfer 

capability or available flowgate capability. Requiring absolute uniformity in criteria and 

assumptions across all transmission service providers would preclude transmission 

service providers from calculating available transfer capability or available flowgate 
Docket No. RM08-19-000, et al. - 156 - 

capability in a way that accommodates the operation of their particular systems. 

Similarly, the Commission believes that it is appropriate for transmission operators to 

retain some discretion. Accordingly, the Commission will not direct the ERO to set a 

specific default value for both the power transfer and outage transfer distribution factors. 

Moreover, transmission service providers are required to include in their available 

flowgate capability implementation documents the criteria used by the transmission 

operator to identify sets of transmission facilities as flowgates that are to be considered in 

the available flowgate capability calculations. Thus, we are satisfied by the transparency 

achieved in the Reliability Standard as written. 

e. MOD-030-2 Treatment of Adjacent Systems

NOPR Proposal

263. In the NOPR, the Commission proposed to approve MOD-030-2 including subrequirements R3.5, R5.2 and R5.3. Sub-requirement R3.5 requires transmission 

operators to make available to the transmission service provider a transmission model to 

determine available flowgate capability that meets that contains modeling data and 

system topology (or equivalent representation) for immediately adjacent and beyond 

reliability coordination areas. When calculation available flowgate capabilities, subrequirement R5.2 requires transmission service providers to include in the transmission 

model expected generation and transmission outages, additions, and retirements within 

the scope of the model as specified in the implementation document and in effect during 

the applicable period of the calculation for the transmission service provider’s area, all 
Docket No. RM08-19-000, et al. - 157 - 

adjacent transmission service providers, and any transmission service providers with 

which coordination agreements have been executed. In addition, under sub-requirement 

R5.3, transmission service providers must, for external flowgates, use the available 

flowgate capability provided by the transmission service provider that calculates 

available flowgate capability for that flowgate. 

Comments

264. Entegra states that the proposed requirements for MOD-030-2, specifically 

sub-requirements R3.5, R5.2, and R5.3, do not require a transmission service provider to 

represent adjacent systems in a realistic manner or to update its representations of 

adjacent systems at the same frequency as the transmission service provider’s models of 

its own system. Entegra states that the requirements also do not have a measure to assess 

the validity of a transmission service provider’s representation of adjacent systems. 

Accordingly, Entegra asks the Commission to direct the ERO to modify MOD-030-2 to 

require transmission service providers to exchange all model data (e.g., load, generation 

profile, net interchange, transactions, outages, and discrete transmission and generation 

elements) necessary to provide an accurate representation of adjacent systems and that 

transmission service providers update the model data with the same frequency that the 

transmission service provider updates models of its own system. Entegra also suggests 

that the revised Reliability Standard should require transmission service providers to 

benchmark and update their representations of adjacent systems on an on-going basis. 
Docket No. RM08-19-000, et al. - 158 - 

Commission Determination

265. All modeling data used by a transmission service provider to represent conditions 

of adjacent systems should reflect actual system operations and the models developed 

should be based on sound engineering principles. The Commission finds that the 

exchange of data provided under these Reliability Standards should provide transmission 

service providers with sufficient data to make realistic estimations of available flowgate 

capability on adjacent systems. Under Requirement R9 of MOD-001-1, a transmission 

service provider must respond to requests for data even when they are made more 

frequently than the transmission service provider updates its available transfer or 

flowgate capability models. Thus, transmission service providers should have access to 

the most current data available for adjacent systems. In light of these existing 

requirements, we deny Entegra’s request to direct the ERO to modify the standard to 

require transmission service providers to update their representations of adjacent systems 

on an on-going basis. 

266. Pursuant to the modifications to MOD-001-1 directed above, transmission service 

providers will be required to benchmark and update their available transfer or flowgate 

capability calculations. This benchmarked data should provide a sufficient basis to 

determine whether transmission service providers are modeling adjacent systems in a 

realistic manner. The Commission will address concerns of unrealistic modeling of 

adjacent systems on a case-by-case basis if, for example, the matter is raised in a 
Docket No. RM08-19-000, et al. - 159 - 

complaint before the Commission. Thus, the Commission declines to direct the 

modification proposed here. 

f. MOD-030-2 Effective Date

Comment

267. Entergy supports NERC’s implementation plan with respect to MOD-030-2, 

which would require compliance one calendar year after approval of MOD-030-2 and its 

related three standards (MOD-001-1, MOD-028-1, and MOD-029-1) by all appropriate 

regulatory authorities. Because MOD-030-2 requires information from neighboring 

reliability entities for use in the development of its available transfer capability and 

available flowgate capability values and some of that information may not be available 

until MOD-028-1 and MOD-29-1 become effective, Entergy agrees with NERC that it is 

essential that all three methodologies and MOD-001-1 become effective at the same time. 

268. Entergy also asks clarification regarding the stated effective date. Entergy 

contends that defining the effective date of MOD-030-2 with reference to a detail in an 

earlier version of the Reliability Standard that is proposed to be superseded creates a lack 

of clarity. Accordingly, Entergy recommends that NERC revise MOD-030-2 to 

incorporate the same effective date language used in MOD-001-1, MOD-028-1, and 

MOD-029-1. 

Commission Determination

269. As noted above, the Commission approves the proposal to make these Reliability 

Standards effective on the first day of the first calendar quarter that is twelve months 
Docket No. RM08-19-000, et al. - 160 - 

beyond the date that the Reliability Standards are approved by all applicable regulatory 

authorities. Although MOD-030-2 defines its effective date with reference to the 

effective date of MOD-030-1, the Commission finds that this direction is sufficiently 

clear in the context of the current proceeding. To the extent necessary, we clarify 

MOD-030-2 shall become effective on the first day of the first calendar quarter that is 

twelve months beyond the date that the Reliability Standards are approved by all 

applicable regulatory authorities. The Commission also directs the ERO to make explicit 

such detail in any future version of this or any other Reliability Standard. 

C. Violation Risk Factors and Violation Severity Levels

NOPR Proposal

270. The Commission proposed to accept NERC’s commitment to file violation 

severity levels and violation risk factors at a later time. The Commission noted that the 

Violation Severity Level Order was issued after NERC developed the violation severity 

level assignments for the Reliability Standards at issue in this proceeding.121 The 

Commission acknowledged that, as a result, NERC was unable to evaluate and modify 

the proposed violation severity levels to comply with the Commission’s guidelines prior 

to filing the proposed Reliability Standards. The Commission therefore proposed to 

direct the ERO to reevaluate the violation severity levels associated with all of the 

 121 NOPR, FERC Stats. & Regs. ¶ 32,641 at P 123, citing North American Electric 

Reliability Corp., 123 FERC ¶ 61,284, at P 20-35 (2008) (Violation Severity Level 

Order). 
Docket No. RM08-19-000, et al. - 161 - 

proposed Reliability Standards based on the Commission’s guidelines outlined in the 

Violation Severity Level Order and prepare appropriate revisions. In addition, the 

Commission proposed 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 definition and guidance provided in 

the Violation Risk Factor Order and the Violation Risk Factor Rehearing Order.122 The 

Commission proposed to direct NERC to file revised violation severity levels and 

violation risk factors no later than 120 days before the Reliability Standards become 

effective. 

Comments

271. Puget Sound states that it supports the Commission’s proposal that NERC not file 

violation risk factors and violation severity levels at this time. Puget Sound also states 

that it supports the Commission’s proposal to allow NERC staff time to review the 

violation risk factors through an open stakeholder process to ensure that they are 

consistent with Commission precedent. Puget Sound also contends that no requirement 

of the proposed MOD Reliability Standards should be assigned a violation risk factor 

exceeding “Lower” because the potential violations of these standards would not directly 

affect the electrical state or the capability of the Bulk-Power System, or the ability to 

 122 North American Electric Reliability Corp., 119 FERC ¶ 61,145, at P 9 

(Violation Risk Factor Order), order on reh’g, 120 FERC ¶ 61,145 (2007). 
Docket No. RM08-19-000, et al. - 162 - 

effectively monitor and control the Bulk-Power System.123 For the same reason, Puget 

Sound also contends that the MOD Reliability Standards should not be assigned violation 

severity levels greater than “Lower.” 

272. The Joint Municipals also argue that the Commission should direct NERC to 

assign low violation risk factors to the Reliability Standards approved here. The Joint 

Municipals point out, as the Commission did in the NOPR, that the NERC Reliability 

Standards drafting team adjusted the violation risk factors to “lower” from “medium,” in 

view of what appears to be the consensus that the available transfer capability-related 

Reliability Standards are not critical to system reliability. 

273. By contrast, Midwest ISO contends that the original set of violation risk factors 

assigned by the Reliability Standard drafting team and submitted to industry vote are 

valid. Midwest ISO states that the violation risk factors already have been through an 

open stakeholder process in which the proposed Reliability Standards were commented 

on and voted upon multiple times. Further, Midwest ISO contends that continued delay 

in filing the violation risk factors contravenes NERC’s earlier commitment to file in a 

timely manner. 

Commission Determination

274. The Commission adopts the NOPR proposal and directs the ERO to reevaluate the 

violation risk factors and violation severity levels associated with all of the proposed 

 123 Citing Violation Risk Factor Order,119 FERC ¶ 61,145 at P 9. 
Docket No. RM08-19-000, et al. - 163 - 

 

MOD Reliability Standards based on the Commission’s precedent and to prepare 

appropriate revisions. The Commission notes that in Order No. 722, the Commission 

encouraged the ERO to develop a new and comprehensive approach that would better 

facilitate the assignment of violation severity levels and violation risk factors both 

prospectively and to approved Reliability Standards.124 NERC responded by making an 

informational filing proposing a new method for assigning violation risk factors and 

violation severity levels. Although the Commission reserves judgment of the merits of 

the ERO’s proposals presented in the informational filing, the Commission accepts the 

ERO’s commitment to reevaluate the violation risk factors and violation severity levels 

associated with these MOD Reliability Standards through an open stakeholder process to 

ensure that they are consistent with the intent of violation risk factor definitions and 

Commission precedent. The Commission hereby directs the ERO to file revised violation 

severity levels and violation risk factors no later than 120 days before the Reliability 

Standards become effective. In light of this reevaluation of the violation severity levels 

and violation risk factors, we find the arguments raised by Puget Sound and the Joint 

Municipals to be premature. 

 

124 Version Two Facilities Design, Connections and Maintenance Reliability 

Standards, Order No. 722, 126 FERC ¶ 61,255, at P 45 (2009). 
Docket No. RM08-19-000, et al. - 164 - 

D. Disposition of Other Reliability Standards

1. MOD-010-1 through MOD-025-1

NOPR Proposal

275. In the NOPR, the Commission proposed to allow NERC to address revisions to 

MOD-010 through MOD-025 to incorporate a requirement for 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. These Reliability Standards are generally 

intended to establish consistent data requirements, reporting procedures and system 

models for use in reliability analysis. As such, the Commission proposed to find that 

NERC is correct that these Reliability Standards were not a part of the available transfer 

capability modifications required in Order Nos. 890 and 693. 

Commission Determination

276. The Commission hereby adopts its NOPR proposal and will allow NERC to 

address revisions to MOD-010 through MOD-025 through a separate project. In Order 

No. 693, the Commission identified nine Reliability Standards as the core of the available 

transfer capability initiative directed in Order No. 890.125 None of the Reliability 

Standards MOD-010 through MOD-025 were identified as part of that initiative. 

 125 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 206. 
Docket No. RM08-19-000, et al. - 165 - 

2. Reliability Standards to be Retired or Withdrawn

NOPR Proposal

277. In the NOPR, the Commission proposed 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 proposed 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 are, upon the effectiveness of the proposed MOD Reliability 

Standards, no longer necessary. 

278. The Commission also proposed to not grant NERC’s request to withdraw FAC012-1, nor approve the retirement of FAC-013-1.126 With respect to these two Reliability 

Standards, the Commission disagreed with NERC that they are wholly superseded by the 

MOD Reliability Standards addressed in these proceeding. The Commission noted that, 

under FAC-012-1, reliability coordinators and planning authorities would be required to 

document the methodology used to establish inter-regional and intra-regional transfer 

capabilities and to state whether the methodology is applicable to the planning horizon or 

the operating horizon. The Commission also noted that, under FAC-013-1, reliability 

coordinators and planning authorities are required to establish a set of inter-regional and 

 126 NOPR, FERC Stats. & Regs. ¶ 32,641 at P 138. 
Docket No. RM08-19-000, et al. - 166 - 

 

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. The Commission posited that these FAC 

Reliability Standards were necessary because 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.127 Thus, the Commission 

stated, 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. 

279. 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.128 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.129 The Commission directed the ERO to modify 

FAC-012-1 to provide a framework for the transfer capability calculation methodology 

127 See MOD-001-1, Requirement R2.3. 

128 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 777. 

129 Id. P 782. 
Docket No. RM08-19-000, et al. - 167 - 

that takes account of the need for consistency in the criteria used to calculate transfer 

capabilities.130

Comments

280. NERC does not object to the Commission proposal to retain FAC-012-1 and 

FAC-013-1 but asks the Commission for additional time to make the appropriate 

revisions. Instead of directing NERC to file the proposed modifications within 120 days 

prior to the effective date of the available transfer capability-related MOD Reliability 

Standards, NERC proposes that the Commission instead require that these changes be 

filed 60 days before the Reliability Standards become effective. NERC states that this 

will provide it with additional time to develop these changes in accordance with the 

Reliability Standards development process, and minimize the probability that special 

exceptions to the process be granted in order to meet the Commission’s proposed 

deadline. In addition, NERC states that this delay will help ensure that these changes do 

not take undue precedence ahead of other issues currently prioritizes and being addressed 

in the NERC standards development work plan. 

281. EEI, Duke, First Energy, FPL and Puget Sound object to the Commission’s 

proposal to retain FAC-012-1 and FAC-013-1. EEI states that although the NOPR 

defined the operating horizon to include the next twelve months (i.e., months 2-13), 

Order No. 890 defined the operating horizon as “day-ahead and pre-schedule” and the 

 130 Id. P 779, 782. 
Docket No. RM08-19-000, et al. - 168 - 

 

planning horizon as “beyond the operating horizon.”131 Thus, EEI argues that the 

proposed MOD Reliability Standards provide for the calculation of available transfer 

capability during part of the planning of horizon even though they do not address the 

calculation of available transfer capability beyond month 13. 

282. EEI further contends that there is no reliability concern created by retiring FAC012-1 and FAC-013-1 just as there are no reliability benefits obtained by complying with 

them. EEI contends that this is particularly true in the Eastern Interconnection where the 

Eastern Interconnection Reliability Assessment Group exists as a forum for organizing 

reliability-related modeling and planning activities by defining various studies and cases, 

as well as common assumptions, for the long-term planning horizon. Thus, EEI 

contends, the Commission should not view the retiring of FAC-012-1 and FAC-013-1 as 

creating a vacuum; rather, the proposed MOD Reliability Standards have “wholly 

superseded” them by replacing their only useful components. In the alternative, if the 

Commission decides to retain FAC-012-1, EEI suggests that the Commission direct 

NERC to consider moving the substantive content of FAC-012-1 into a technical 

guidance document and have the document appended to an approved FAC Reliability 

Standard. 

283. Duke states that it supports NERC’s proposal to retire FAC-013-1 when the MOD 

Reliability Standards become effective and to withdraw its request for approval of 

131 Citing Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 323 and 

Attachment C. 
Docket No. RM08-19-000, et al. - 169 - 

FAC-012-1. Duke states that it does not believe that available transfer capability 

calculations made past a 13 month period are sufficient to support reliable long-term 

transmission service and so supports EEI’s comments related to calculations made past 

month 13. Duke also contends that, in the Eastern Interconnect region, regional 

assessments and planning are occurring for transfer capabilities in the planning horizon 

(i.e., period of time after 13 months) in various forums such as Southeastern Electric 

Reliability Council’s long-term study group and the Eastern Interconnection Reliability 

Assessment Group. Duke states that other efforts exist in response to Order No. 890’s 

regional planning requirements such as the Southeast Inter-Regional Participation 

Process and the North Carolina Transmission Planning Collaborative. Duke contends 

that these and other regional planning efforts will effectively ensure that levels of transfer 

capability are maintained to meet regional and interconnection wide reliability 

requirements in the planning horizon. 

284. If the Commission adopts FAC-012-1 and retains FAC-013-1, then Duke requests 

that the Commission require FAC-012-1 to be revised to focus on the development of a 

methodology for calculation inter-regional and intra-regional transfer capabilities for use 

in assessing the ability of the Bulk-Power System to support potentially large, diverse 

regional transfers of power in a reliable manner, rather than calculation of total transfer 

capabilities or available transfer capabilities for evaluation of service requests. Duke 

contends that there is no Commission requirement for the posting of total transfer 

capabilities and/or available transfer capabilities beyond 13 months. Further, if the 
Docket No. RM08-19-000, et al. - 170 - 

 

Commission approves FAC-012-1, Duke requests that it be made applicable to just the 

planning coordinator, and not the reliability coordinator, since the Reliability Standard 

would focus on the planning timeframe. Similarly, Duke recommends that the 

Commission direct the ERO to modify FAC-013-1 to establish and communicate the 

transfer capabilities developed using the methodology specified in FAC-012-1. 

285. FirstEnergy agrees that the MOD-001-1 addresses the scheduling, operating and 

planning horizons, as those terms were described in Order No. 693.132 However, if the 

Commission chooses to direct the ERO to retain FAC-012-1 and FAC-013-1, FirstEnergy 

asks the Commission to limit the FAC standards to the use of transmission capability for 

transmission planning and remove redundant provisions for the calculation of transfer 

capability addressed elsewhere in the MOD Reliability Standards, especially for other 

purposes such as the calculation of available transfer capability. FirstEnergy states that 

the FAC and the MOD Reliability Standards each address the calculation of transfer 

capability in the operational time-period. To eliminate this redundancy, FirstEnergy 

suggests that the Commission direct the ERO to assign the treatment of operational 

transfer capability to the MOD Reliability Standards and eliminate the reference to the 

use of transfer capability in the operational horizon in the operational standards. 

FirstEnergy further contends that the FAC Reliability Standards are ambiguous since they 

require the calculation of a parameter, transfer capability in the planning horizon, for 

132 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1047. 
Docket No. RM08-19-000, et al. - 171 - 

which the purpose is not described or specified. Nevertheless, FirstEnergy states that it 

strongly supports the standard drafting team’s conclusion that the best method for 

addressing total transfer capability accurately and clearly is within the MOD Reliability 

Standards. 

286. FPL contends that the elimination of FAC-012-1 and FAC-013-1 would not create 

a void. FPL states that the total transfer capability and available transfer capability in the 

long-term planning horizon are not tied to a specific path for posting purposes, but 

instead look at the transmission network limits for which expansion projects would be 

initiated to meet the long-term needs for firm transmission service. Although the MOD 

Reliability Standards do not require the posting of transfer capabilities beyond 13 

months, FPL states that this is only a minimum requirement that reflects the impractical 

nature of pre-determined transfer capability calculations for the planning horizon after the 

13th month. FPL contends that the study of transmission service requests beyond the 13th

month of the planning horizon requires specific knowledge and assumptions, and such 

requests could not be granted based on pre-determined calculations alone. For these 

reasons FPL agrees with NERC’s recommendation to withdraw Reliability Standard 

FAC-012-1 and retire FAC-013-1. 

287. Pacific Northwest contends that MOD-003-0 should not be retired or withdrawn. 

Pacific Northwest states that MOD-030-2 requires regional reliability organizations to 

develop and document procedures that allow transmission service customers to inquire 

about calculations of total transfer capability and available transfer capability, timeframes 
Docket No. RM08-19-000, et al. - 172 - 

for response and posting requirements applicable to the regional reliability organization. 

Pacific Northwest contends that this procedure fills gaps in the current NAESB business 

practice in that the procedure facilitates the provision of information about available 

transfer capability and total transfer capability calculations for transmission paths with 

multiple owners but with one available transfer capability rating and one seasonal 

operating transfer capability rating. 

Commission Determination

288. The Commission hereby adopts the NOPR proposal and approves 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 finds 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 are, upon the effectiveness of the proposed MOD Reliability 

Standards, no longer necessary. 

289. Consistent with its NOPR proposal, the Commission finds that NERC has not 

addressed the requirements of Order No. 693 with regard to the calculation of transfer 

capabilities in the planning horizon. In Order No. 693 the Commission 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 
Docket No. RM08-19-000, et al. - 173 - 

 

system.133 As EEI observes, in Order No. 890, the Commission offered, as an example, a 

possible definition of the operating horizon as the day-ahead and pre-scheduling periods 

and the planning horizon as anything beyond the operating horizon.134 However, NERC 

has already defined the near-term planning horizon as years one through five in subrequirement R1.2 of TPL-005. The Commission believes that this definition should be 

consistent throughout the Reliability Standards. 

290. The Commission recognizes that the calculation of transfer capabilities in the 

planning horizon (years one through five) may not be so accurate to support long-term 

scheduling of the transmission system but we do believe that such forecasts will be useful 

for long-term planning, in general, by measuring sufficient long-term capacity needed to 

ensure the reliable operation of the Bulk-Power System. Although regional planning 

authorities have developed similar efforts in response to Order No. 890, we believe that 

the requirements imposed by FAC-012 and FAC-013 need not be duplicative of those 

existing efforts and, by contrast, should be focused on improving the long-term reliability 

of the Bulk-Power System pursuant to the ERO’s Reliability Standards. We believe that 

these responsibilities would be appropriately assigned to the planning coordinator and not 

the reliability coordinator. 

133 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 782. 

134 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 323. 
Docket No. RM08-19-000, et al. - 174 - 

291. The Commission hereby adopts its NOPR proposal to deny NERC’s request to 

withdraw FAC-012-1 and retire FAC-013-1. Instead, pursuant to section 215(d)(5) of the 

FPA and section 39.5(f) of our regulations, the Commission directs the ERO to develop 

modifications to FAC-012-1 and FAC-013-1 to comply with the relevant directives of 

Order No. 693135 and, as otherwise necessary, to make the requirements of those 

Reliability Standards consistent with those of the MOD Reliability Standards approved 

herein as well as this Final Rule. These modifications should also remove redundant 

provisions for the calculation of transfer capability addressed elsewhere in the MOD 

Reliability Standards. In making these revisions, the ERO should consider the 

development of a methodology for calculation of inter-regional and intra-regional transfer 

capabilities. The Commission accepts the ERO’s request for additional time to prepare 

the modifications and so directs the ERO to submit the modifications to FAC-012-1 and 

FAC-013-1 no later than 60 days before the MOD Reliability Standards become 

effective. 

E. Applicability

Comments

292. Supported by Austin, ERCOT requests that the Commission act to ensure the 

proposed Reliability Standards are not applied to the ERCOT region. ERCOT contends 

that the proposed Reliability Standards have no value in the ERCOT region because 

 135 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 779, 782. 
Docket No. RM08-19-000, et al. - 175 - 

ERCOT does not have a transmission market and it manages congestion by employing a 

security constrained economic dispatch. ERCOT further contends that the proposed 

MOD Reliability Standards are actually counter-productive to the efficient operation of 

the ERCOT grid and markets. ERCOT states that there are two primary concerns 

associated with available transfer capability, underutilization and oversubscription of the 

grid. ERCOT contends that these concerns only apply in regions that have transmission 

markets, and primarily physical markets, where the available transfer capability 

calculation can actually be performed because there are transmission obligations that can 

be netted against total transfer capability. ERCOT further contends that neither concern 

arises in the ERCOT region because there is no transmission market. 

293. Similarly, ERCOT contends that capacity benefit margin has no relevance in 

ERCOT because there is no transmission market and all energy schedules are respected 

inside ERCOT without the need for transmission reservations. ERCOT further argues 

that requiring ERCOT to set aside transmission capacity to meet the proposed capacity 

benefit margin obligation would actually be counter-productive because it would inhibit 

efficient dispatch of the system, thereby creating artificial congestion to respect the 

reserved capacity benefit margin. ERCOT also contends that transfer reliability margin is 

irrelevant in the ERCOT region because ERCOT manages all operational issues through 

re-dispatch. Furthermore, because available transfer capability is undefined in the 

ERCOT region, ERCOT argues that the Reliability Standards establishing the calculation 

methodologies are also irrelevant with the region. 
Docket No. RM08-19-000, et al. - 176 - 

294. NYISO asks the Commission to clarify that the MOD Reliability Standards should 

be interpreted with a reasonable degree of flexibility to accommodate the special 

characteristics of ISOs and RTOs. NYISO contends that the MOD Reliability Standards 

were written to accommodate physical reservation transmission systems and do not 

include provisions that accommodate the special characteristics of NYISO’s financial 

reservation model. NYISO states that it has reached an informal agreement with NERC 

through which NYISO believes it could comply with the requirements of MOD-029-1 as 

written. NYISO also asks the Commission to indicate that it will entertain a future 

NYISO request for confirmation that it is in compliance with the NERC Reliability 

Standards. NYISO further asks the Commission to clarify that it expects NERC and the 

regional entities to accommodate financial transmission rights based open access market 

designs when evaluating the compliance of the NYISO, and to the extent relevant, other 

ISOs and RTOs, with the proposed MOD Reliability Standards. 

295. Entergy requests clarification whether entities that use a value of zero for transfer 

reliability margin and capacity benefit margin are technically maintaining transfer 

reliability margin or capacity benefit margin and, if not, whether MOD-004-1 and 

MOD-008-1 apply to those entities. Entergy contends that if the transfer reliability 

margin and capacity benefit margin Reliability Standards do apply to entities that 

maintain a value of zero, the Reliability Standards should only require that the 

transmission reserve margin and capacity benefit margin implementation documents state 

that no capacity benefit margin or transfer reliability margin set-aside exists. In addition, 
Docket No. RM08-19-000, et al. - 177 - 

Entergy requests clarification whether MOD-008-1 applies to entities that only use 

transfer reliability margin in system impact studies when evaluating long-term firm 

transmission service requests and whether such entities would be required to maintain a 

transfer reliability margin implementation document. 

Commission Determination

296. In Order No. 693, the Commission found that a Reliability Standard must provide 

for the Reliable Operation of the Bulk-Power System facilities and may impose a 

requirement on any user, owner or operator of such facilities.136 The Commission went 

on to say that a Reliability Standard should be a single standard that applies across the 

North American Bulk-Power System to the maximum extent this is achievable taking into 

account physical differences in grid characteristics and regional Reliability Standards that 

result in more stringent practices.137 A Reliability Standard can also account for regional 

variations in the organizational and corporate structures of transmission owners and 

operators, variations in generation fuel type and ownership patterns, and regional 

variations in market design if these affect the proposed Reliability Standard. In addition, 

a Reliability Standard should have no undue negative effect on competition. Following 

these principles, the Commission finds that the applicability of these Reliability 

 136 Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 5. 

137 Id. P 6. 
Docket No. RM08-19-000, et al. - 178 - 

 

Standards should take into consideration regional differences such as those highlighted 

by commenters. 

297. With respect to the enforcement of these Reliability Standards, the Commission 

finds that their requirements are sufficiently clear so that an entity should be aware of 

what it must do to comply.138 The Commission believes that an entity is able to comply 

with these Reliability Standards even if there are physical differences in grid 

characteristics or variations in market design that create challenges. To the extent that a 

transmission provider, an ISO or RTO has a concern regarding the enforcement of these 

Reliability Standards, the Commission believes that this is a compliance issue best 

addressed on a case-by-case basis in the context of a compliance proceeding. For this 

same reason, the Commission declines to offer its opinion as to whether NYISO is in 

compliance with the Reliability Standards. As the ERO for North America, NERC is 

uniquely qualified to enforce its own Reliability Standards. 

298. In response to Entergy’s comment, the Commission notes that MOD-008-1 is 

applicable only to transmission operators that maintain transmission reliability margin. 

Although MOD-004-1 is not as explicit with regard to its applicability, we believe that its 

applicability is implicitly reserved to those entities that maintain capacity benefit margin. 

Thus, it does not appear that Entergy, or any other entity, would be in violation of 

MOD-004-1 or MOD-008-1 if it does not maintain transmission reliability margin or 

138 See id. P 254.
Docket No. RM08-19-000, et al. - 179 - 

capacity benefit margin. Similarly, in response to ERCOT, we believe that it is 

appropriate to exempt entities within ERCOT from complying with these Reliability 

Standards. We agree that, due to physical differences of ERCOT’s transmission system, 

the MOD Reliability Standards approved herein would not provide any reliability benefit 

within ERCOT. 

F. Definitions

NOPR Proposal

299. NERC proposed to modify its Glossary of Terms to add twenty definitions that are 

used in the five proposed Reliability Standards, including the following definitions of 

“ATC Path”, “Business Practices”, and “Postback”: 

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.139

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.

Postback: Positive adjustments to Available Transfer 

 139 See 18 CFR 37.6(b)(1). 
Docket No. RM08-19-000, et al. - 180 - 

 

Capability (ATC) or Available Flowgate Capability (AFC) as 

defined in Business Practices. Such Business Practices may 

include processing of redirects and unscheduled service. 

300. In the NOPR, the Commission proposed to approve the addition of these terms to 

the NERC Glossary. The Commission also proposed to direct NERC to modify the 

definition of Postback to eliminate its reference to Business Practices, another defined 

term. The Commission observed that the definition of Business Practices includes a 

reference to the “regional reliability organization.” The Commission stated that, in Order 

No. 693, the Commission directed NERC to eliminate references to regional reliability 

organizations as responsible entities in the Reliability Standards because such entities are 

not users, owners or operators of the Bulk-Power System. Accordingly the Commission 

proposed 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. The Commission noted, however, that Regional Entity is not currently defined in 

the NERC Glossary. The Commission therefore proposed to direct NERC to develop a 

definition of Regional Entity consistent with section 215(a) of the FPA140 and 18 CFR 

39.1 (2008), to be included in the NERC Glossary. 

140 16 U.S.C. 824o. 
Docket No. RM08-19-000, et al. - 181 - 

Comments

301. Puget Sound states that it agrees with the Commission that the term “Postback” is 

not fully determinative and requests that the Commission reject the definition as 

redundant and unnecessary. Puget Sound states that for a particular point of receipt/point 

of delivery combination, the existing transmission capacity component includes 

confirmed reservations utilized on that particular point of receipt/point of delivery 

combination. Puget Sound states that processing firm redirects or annulments to the 

confirmed reservation reduces the existing commitment component, which in turn 

increases the resultant available transfer capability, achieving the same result as the 

desired effect of the Postback term. Puget Sound further contends that requiring a 

Postback component assumes that once a reservation is confirmed on a particular point of 

reservation/point of receipt combination the impact of the confirmed reservation will 

always be present in the available transfer capability calculation, regardless of future 

redirects, annulments, or recalls that are processed. Puget Sound contends that accepting 

the Postback definition would add an unnecessary component to the available transfer 

capability formula, increasing the recordkeeping and documentation burden for 

applicable entities. 

302. SMUD and Salt River ask the Commission to clarify that the proposed definition 

of “ATC Path” does not limit a transmission provider’s flexibility to treat multiple 

parallel interconnections between balancing authorities as a single path. NERC proposes 

to define “ATC Path” as: “Any combination of Point of Receipt and Point of Delivery for 
Docket No. RM08-19-000, et al. - 182 - 

which [available transfer capability] is calculated; and any Posted Path.” SMUD and Salt 

River note that this definition references the definition of “Posted Path” in the 

Commission’s regulations, 18 CFR § 37.6(b)(1), which defines “Posted Path” as any 

control area to control area interconnection and any path for which a customer requests to 

have available transfer capability and total transfer capability posted. They contend that 

one possible way to interpret “control area to control area interconnection” would be to 

treat each physical interconnection between Balancing Authorities as creating a separate 

available transfer capability path. They argue that the Commission should clarify the 

definition so as to recognize that available transfer capability paths may or should be 

comprised of multiple, parallel interconnections between Balancing Authorities as 

reliability interests determine. 

303. SMUD and Salt River also ask the Commission to direct the ERO to modify the 

definition of “ATC Path” to remove reference to the Commission’s regulations. They 

argue that the reference is inappropriate as applied to them because SMUD and Salt River 

are not subject to the Commission’s regulations. They also contend that confusion could 

arise if the Commission revises its definition of Posted Path and thereby effectively 

modifies the Reliability Standards. 

Commission Determination

304. The Commission believes that the definition of Postback is not fully 

determinative. NERC should be able to define this term without reference to the 

Business Practices, another defined term. Accordingly, the Commission adopts its NOPR 
Docket No. RM08-19-000, et al. - 183 - 

proposal and directs the ERO to develop a modification to the definition of Postback to 

eliminate the reference to Business Practices. Although we are sensitive to Puget 

Sound’s concern that the required Postback component may increase the recordkeeping 

burden on some entities, in other regions the component may be critical. We disagree 

that the term’s existence assumes that once a reservation is confirmed on a particular 

point of reservation/point of receipt combination the impact of the confirmed reservation 

will always be present in the available transfer capability calculation. However, we 

would consider suggestions that would allow entities to comply with the requirements as 

efficiently as possible, such as a regional difference through the ERO’s standards 

development procedure. 

305. The Commission also adopts its NOPR proposal to direct the ERO to develop a 

modification to the definition of Business Practices that would remove the reference to 

regional reliability organizations and replace it with the term Regional Entity. We also 

direct the ERO to develop a definition of the term Regional Entity to be included in the 

NERC Glossary. 

306. We agree with SMUD and Salt River that the definition of “ATC Path” should not 

limit a transmission provider’s flexibility to treat multiple parallel interconnections 

between balancing authorities as a single path, and that available transfer capability paths 

may comprise multiple, parallel interconnections between Balancing Authorities when 

such treatment is appropriate to maintain reliability. We also agree that the definition 

should not reference the Commission’s regulations. The Commission’s regulations are 
Docket No. RM08-19-000, et al. - 184 - 

not applicable to all registered entities and are subject to change. We therefore direct the 

ERO to develop a modification to the definition of “ATC Path” that does not reference 

the Commission’s regulations. 

IV. Information Collection Statement

307. 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 1995.141 OMB’s regulations require OMB to 

approve certain information collection requirements imposed by agency rule.142

308. The Commission solicited comments on the need for and the purpose of the 

information contained in these Mandatory Reliability Standards and the corresponding 

burden to implement them. The Commission did receive comments on specific 

requirements in the Reliability Standards and how their impact would be burdensome. 

We have addressed those concerns elsewhere in this Final Rule. However, we did not 

receive comments on our reporting burden estimates. The Commission has updated the 

burden requirements to be consistent with our directions in this Final Rule. 

Burden Estimate: The public reporting and records retention burdens for the proposed 

reporting requirements and the records retention requirement are as follows.143 

 141 44 U.S.C. 3507(d). 

142 5 CFR 1320.11. 

143 These burden estimates apply only to this Final Rule and do not reflect upon all 

of FERC-516 or FERC-717. 
Docket No. RM08-19-000, et al. - 185 - 

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. x $925 (off site storage) = $126,725 

Total costs = $2,997,115 

Labor $ ($2,811,240+ $59,150) + Recordkeeping Storage Costs ($126,725) 

309. OMB’s regulations require it to approve certain information collection 

requirements imposed by an agency rule. The Commission is submitting notification of 

this Final 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 
Docket No. RM08-19-000, et al. - 186 - 

Action: Final Rule 

OMB Control No. 1902-0244 

Respondents: Business or other for profit 

Frequency of responses: On occasion. 

Necessity of the Information: 

310. Internal Review: The Commission has reviewed the approved 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. 

311. 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.]. 

312. 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 
Docket No. RM08-19-000, et al. - 187 - 

Energy Regulatory Commission, phone (202) 395-4650, fax: (202) 395-7285, e-mail: 

oira_submission@omb.eop.gov.]. 

V. Environmental Analysis

313. 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.144 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.145

VI. Regulatory Flexibility Act

314. The Regulatory Flexibility Act of 1980 (RFA)146 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. Transmission service providers and transmission 

operators are entities responsible for the reliability of a transmission system. They 

operate or direct the operations of the transmission facilities or control facilities used for 

 144 Regulations Implementing the National Environmental Policy Act of 1969, 

Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. ¶ 30,783 (1987). 

145 18 CFR 380.4(a)(5). 

146 5 U.S.C. 601-612. 
Docket No. RM08-19-000, et al. - 188 - 

 

the transmission of electric energy in interstate commerce. Accordingly, these entities do 

not fall typically within the definition of a small entity.147

315. Section 215(d)(2) of the FPA provides that the Commission may approve, by rule 

or order, a proposed Reliability Standard or modification to a proposed Reliability 

Standard if it meets the statutory standard for approval, giving due weight to the technical 

expertise of the ERO. Alternatively, the Commission may remand a Reliability Standard 

pursuant to section 215(d)(4) of the FPA. Further, the Commission may order the ERO 

to submit to the Commission a proposed Reliability Standard or a modification to a 

Reliability Standard that addresses a specific matter if the Commission considers such a 

new or modified Reliability Standard appropriate to “carry out” section 215 of the FPA. 

The Commission’s action in this final rule is based on its authority pursuant to section 

215 of the FPA. 

316. 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 per year.148 The Commission does not consider 

this a substantial number. Based on this understanding, the Commission certifies that this 

147 The 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). 

148 Id. 
Docket No. RM08-19-000, et al. - 189 - 

Final Rule will not have a significant economic impact on a substantial number of small 

entities. Accordingly, no regulatory flexibility analysis is required. 

VII. Document Availability

317. 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 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington, DC 20426. 

318. 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. 

319. User assistance is available for eLibrary and the FERC’s website during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email 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. 
Docket No. RM08-19-000, et al. - 190 - 

VIII. Effective Date and Congressional Notification

320. These regulations are effective [insert date that is 60 days from publication in 

the Federal Register]. The Commission notes that although the determinations made in 

this Final Rule are effective [insert date that is 60 days from publication in the 

Federal Register], the MOD Reliability Standards approved herein will not become 

effective until the first day of the first quarter no sooner than one calendar year after 

approval by all appropriate regulatory authorities where approval is required. The 

Commission has determined, with the concurrence of the Administrator of the Office of 

Information and Regulatory Affairs of OMB, that this Rule is not a “major rule” as 

defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 

1996. 

List of subjects in 18 CFR Part 40 

By the Commission. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 
Docket No. RM08-19-000, et al. - 191 - 

Appendix A: Commenting Party Acronyms 

Abbreviation Commenter Name 

APPA American Public Power Association 

Austin Austin, City of 

Avista Avista Corporation 

Bonneville Bonneville Power Administration 

ColumbiaGrid ColumbiaGrid 

Cottonwood Cottonwood Energy Company 

Duke Duke Energy Carolinas, LLC 

EEI Edison Electric Institute 

EPSA Electric Power Supply Corporation 

ERCOT Electric Reliability Council of Texas, Inc. 

Entegra Entegra Power Group LLC 

Entergy Entergy Services Inc. 

FirstEnergy FirstEnergy Service Company 

FPL Florida Power & Light Company 

Georgia Georgia Transmission Corporation 

ISO/RTO Council ISO/RTO Council 

ITC Companies 

International Transmission Company, Michigan Electric 

Transmission Company, LLC, and ITC Midwest LLC 

LADWP Los Angeles Dept. of Water and Power 

MISO Midwest ISO 

Modesto Modesto Irrigation District 

Nevada Companies Nevada Power Company and Sierra Pacific Power Company

NYISO New York ISO 

NERC North American Electric Reliability Corp. 

Northwest Utilities Northwest Requirements Utilities 

Northwestern Northwestern Corporation 

Pacific Northwest Pacific Northwest Generating Cooperative 

PacifiCorp PacifiCorp 

Public Power Council Public Power Council 

Snohomish Public Utility District No. 1 of Snohomish County 

Puget Sound Puget Sound Energy, Inc. 

SMUD Sacramento Municipal Utility District 

Salt River Salt River Project 

Joint Municipals 

South Carolina Public Service Authority, Sacramento 

Municipal Utility District and MEAG Power 

SWAT 

Southwest Area Transmission Sub-Regional Planning 

Group 
Docket No. RM08-19-000, et al. - 192 - 

Abbreviation Commenter Name 

TAPS Transmission Access Policy Study Group 

TANC Transmission Agency of Northern California 

Tucson Tucson Electric Power Company