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Daily Rules, Proposed Rules, and Notices of the Federal Government

DEPARTMENT OF ENERGY

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

AGENCY: Federal Energy Regulatory Commission, DOE.
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 SS 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 approved here.
DATES: Effective Date:This rule will become effective February 8, 2010.
Issued November 24, 2009.
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:

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 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 VI. Regulatory Flexibility Act 314 VII. Document Availability 317 VIII. Effective Date and Congressional Notification 320 Before Commissioners: Jon Wellinghoff, Chairman;Suedeen G. Kelly, Marc Spitzer,and Philip D. Moeller.

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 Commission-certified Electric Reliability Organization (ERO) for the United States.2 The approved Reliability Standards pertain to methodologies for the consistent and transparent 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 approved MOD Reliability Standards.

116 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).

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

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 withoutconsidering 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.

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).

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).

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 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.

616 U.S.C. 824o(d)(2).

7Reliability entities include: Transmission service providers, planning coordinators, reliability coordinators, and transmission operators as those entities are defined in the NERCGlossary 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).

4. On March 19, 2009, the Commission issued its Notice of Proposed Rulemaking (NOPR) proposing to approve the six MODReliability Standards.8 The Commission 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.

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 Standards for the Bulk-Power System,74 FR 12747 (March 25, 2009), FERC Stats. Regs. ¶ 32,641 (2009) (“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 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 thepro formaOATT 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, deviations that were consistent with or superior to thepro formaOATT's terms and conditions.

916 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. 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 Groupv.FERC,225 F.3d 667 (D.C. Cir. 2000),aff'd sub nom. New Yorkv.FERC,535 U.S. 1 (2002).

11This 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 SeeOrder No. 888, FERC Stats. Regs. ¶ 31,036 at 31,769-70 (noting that thepro formaOATT 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).

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.

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).

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 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

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

15 Id.at 31,750.

16 Id.

17 Id.

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 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.

18Order No. 888, FERC Stats. Regs. ¶ 31,036 at 31,749 n.610.

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, asmodified 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 thepro formaOATT adopted 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.

19FPA section 215(d)(5). 16 U.S.C. 824o(d)(5).

11. The Commission stated in Order No. 890 that the available transfer capability-related Reliability Standards should, at a minimum, provide a framework for available transfer capability, total transfer capability and existing transmission commitments calculations. The Commission did not require that there be just one computational process for calculating available transfer capability because, among other things, it found that the potential for discrimination and decline in reliability level does not lie primarily in the choice of an available transfer capability calculation methodology, but rather in the consistent application of its components, input and exchange data, and modeling assumptions.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

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

21 Id.P 1030.

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 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

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

23 Id.P 1010.

24 Id.

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

26Order 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.

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, 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

27The Reliability Standards were originally due on December 10, 2007.SeeOrder 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.SeeNERC 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.

28NERC 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.”

29The 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 Web site,http://www.nerc.com.

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.

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 Systembeyond 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 capability-related 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 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 ensure that any limitation will be applied in a manner that ensures open access and promotes competition.

30As 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).

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 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 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 itsplanning 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 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

31 SeeOrder No. 890, FERC Stats. Regs. ¶ 31,241 at P 237; Order No. 693, FERC Stats. Regs. ¶ 31,242 at P 1051.

32Order No. 693, FERC Stats. Regs.¶ 1,242 at P 1057;see alsoOrder No. 890, FERC Stats. Regs. ¶ 31,241 at P 292.

33 SeeOrder No. 890, FERC Stats. Regs. ¶ 31,241 at P 301; Order No. 693, FERC Stats. Regs. ¶ 31,242 at P 1057.

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 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.

34These include: each planning coordinator, reliability coordinator, and transmission operator associated with the transmission service provider's area; and each planning coordinator, reliability coordinator, and transmission service provider adjacent to the transmission service provider's area.

35Although 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.

25. In Order No. 693, the Commission directed the ERO to develop modifications to the available transfer capability Reliability Standards to include a requirement that applicable entities make available assumptions and contingencies underlying available transfer capability and total transfer capability calculations. NERC contends that this Reliability Standard addresses this issue by requiring disclosure in the available transfer capability implementation document under Requirement R3.1 and part of the data exchange required by Requirement R9. NERC states that it has agreed with NAESB that requirements for posting information are more appropriately addressed through the NAESB process. Accordingly, NERC states that NAESB will be addressing the requirements associated with posting this information, instead of NERC.

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

26. 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.

36 SeeNERC Glossary.

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 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, reliabilitycoordinators, transmission planners, resource planners, and planning coordinators that are within or adjacent to the transmission service provider's area, and to the load-serving entities and balancing authorities within the transmission service providers area, and notify those entities of any changes to the capacity benefit margin implementation document prior to the effective date of the change.

30. Requirements R3 and R4 require each load-serving entity and resource planner 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.

37NERC 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.

31. Requirement R5 requires the transmission service provider to establish at least every 13 months a capacity benefit margin value for each available transfer capability path or flowgate to be used for available transfer capability or available flowgate capability during the 13 full calendar months (months 2-14) following the current month (the month in which the transmission service provider is establishing the capacity benefit margin values). Similarly, Requirement R6 requires the transmission planner to establish a capacity benefit margin value for each available transfer capability path or flowgate to be used in planning during each of the full calendar years two through ten following the current year (the year in which the transmission planner is establishing the capacity benefit margin values). All values must reflect consideration of each of the following, if available: (1) Any studies performed by load-serving entities or resource planners pursuant to Requirement R3 for loads within the transmission service provider's area; or (2) any reserve margin or resource adequacy requirements for loads within the transmission service provider's area established by other entities, such as municipalities, state commissions, regional transmission organizations, independent system operators, regional reliability organizations, or regional entities. Once determined, the capacity benefit margin values will be allocated along available transfer capability paths based on the expected import paths or source regions provided by load-serving entities or resource planners. Capacity benefit margin values for flowgates will be allocated based on the expected import paths or source regions provided by load-serving entities or resource planners and the distribution factors associated with those paths or regions, as determined by the transmission service provider.

32. Requirements R7 and R8 require the transmission service provider and the transmission planner to notify all load-serving entities and resource planners that determined they had a need for capacity benefit margin of the amount, or the amount planned, of capacity benefit margin set aside, 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

38Under 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.

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.

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.

39Energy deficient entities are defined by NERC in the Capacity and Energy Emergencies Reliability Standard.SeeEOP-002-2, Attachment 1.

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 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.

40 CitingOrder No. 693, FERC Stats. Regs.¶ 31,242 at P 1078;see alsoOrder No. 890, FERC Stats. Regs. ¶ 31,241 at P 257.

41 CitingOrder No. 693, FERC Stats. Regs. ¶ 31,242 at P 1105.

42 Citing id.P 1077.

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 ofcapacity 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 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.

43 CitingOrder 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.

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

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 the 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.

46Order No. 693, FERC Stats. Regs. ¶ 31,242 at P 1077.

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.

47 Id.P 1081.

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. 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.

48 SeeNERC Glo