[Federal Register Volume 74, Number 234 (Tuesday, December 8, 2009)]
[Rules and Regulations]
[Pages 64884-64927]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-28620]



[[Page 64883]]

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Part III





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 40



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; Final Rule

  Federal Register / Vol. 74 , No. 234 / Tuesday, December 8, 2009 / 
Rules and Regulations  

[[Page 64884]]


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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

Issued November 24, 2009.

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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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 Sec.  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.

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-          41
     1......................................................
    E. Three Methodologies for Calculating Available                  51
     Transfer Capability....................................
        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                  75
     Reliability Standards..................................
        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              132
             Discrimination.................................
    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            176
             Available Flowgate Capability Values...........
            e. MOD-001-1, Consistent Treatment of                    180
             Assumptions....................................
            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,         254
             Requirement R6.................................

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            d. MOD-030-2, Power Transfer and Outage Transfer         260
             Distribution Factors...........................
            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.
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    \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).
    \3\ 16 U.S.C. 824o(d)(5).
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    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 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.
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    \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).
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    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.
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    \6\ 16 U.S.C. 824o(d)(2).
    \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).
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    4. On March 19, 2009, the Commission issued its Notice of Proposed 
Rulemaking (NOPR) proposing to approve the six MOD

[[Page 64886]]

Reliability 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.
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    \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'').
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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 FPA \9\ 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 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, deviations that were consistent with or superior to the pro forma 
OATT's terms and conditions.
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    \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. & 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).
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    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.
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    \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).
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    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\
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    \14\ Order No. 889, FERC Stats. & Regs. ] 31,035 at 31,749.
    \15\ Id. at 31,750.
    \16\ Id.
    \17\ Id.
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    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.
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    \18\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,749 
n.610.
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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

[[Page 64887]]

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 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.
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    \19\ FPA section 215(d)(5). 16 U.S.C. 824o(d)(5).
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    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\
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    \20\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 1029.
    \21\ Id. P 1030.
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    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\
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    \22\ Order No. 693, FERC Stats. & Regs. ] 31,242.
    \23\ Id. P 1010.
    \24\ Id.
    \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.
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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\
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    \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.
    \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 Web site, http://www.nerc.com.
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    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 System

[[Page 64888]]

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 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.
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    \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).
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    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 its

[[Page 64889]]

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 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\
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    \31\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 237; 
Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1051.
    \32\ Order No. 693, FERC Stats. & Regs. ] 1,242 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.
---------------------------------------------------------------------------

    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.
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    \34\ These 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.
    \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.
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    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.
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    \36\ See NERC 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, reliability

[[Page 64890]]

coordinators, transmission planners, resource planners, and planning 
coordinators that are within or adjacent to the transmission service 
provider's area, and to the load-serving entities and balancing 
authorities within the transmission service providers area, and notify 
those entities of any changes to the capacity benefit margin 
implementation document prior to the effective date of the change.
    30. Requirements R3 and R4 require each load-serving entity and 
resource planner 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \39\ Energy deficient entities are defined by NERC in the 
Capacity and Energy Emergencies Reliability Standard. See EOP-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\ 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.
    \41\ Citing Order 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 of

[[Page 64891]]

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 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\ 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.
    \45\ Citing Order 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.
---------------------------------------------------------------------------

    \46\ Order 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\ See NERC Glossary, available at: http://www.nerc.com/docs/standards/rs/Glossary_2009April20.pdf.
---------------------------------------------------------------------------

    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 to keep a transmission 
reliability margin. Requirement R1 provides that a transmission 
operator must keep a transmission reliability margin implementation 
document that explains how specific risks such as aggregate load 
forecast uncertainty, load distribution uncertainty, and forecast 
uncertainty in transmission system topology \49\ 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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

[[Page 64892]]

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.
---------------------------------------------------------------------------

    \50\ NERC Filing at 32 (citing Order No. 890, FERC Stats. & 
Regs. ] 31,241 at P 273).
---------------------------------------------------------------------------

    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.
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    \51\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1126.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \52\ See Order No. 890, FERC Stats. & Regs. ] 31,241 at P 273.
---------------------------------------------------------------------------

    50. NERC contends that choosing a ``best'' approach to transmission 
reliability margin calculation would require a much more thorough 
technical effort. NERC therefore requests that the Commission provide 
additional guidance on this topic regarding its priority and a 
determination whether or not such an effort should be included in 
NERC's annual planning process.

E. Three Methodologies for Calculating Available Transfer Capability

    51. In Order No. 890, the Commission did not require a uniform 
methodology for calculating available transfer capability. The 
Commission noted that NERC was developing Reliability Standards for 
three available transfer capability calculation methodologies and 
concluded that, if all of the available transfer capability components 
and certain data inputs and assumptions are consistent, the three 
available transfer capability calculation methodologies being developed 
by NERC will produce predictable and sufficiently accurate, consistent, 
equivalent and replicable results.\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.
---------------------------------------------------------------------------

    \53\ Id. P 210.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 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

[[Page 64893]]

total transfer capability using a model that meets the scope specified 
in the requirement and includes rating information specified by 
generator owners and transmission owners whose equipment is represented 
in the model.
    57. Requirement R3 details the information the transmission 
operator must include in its determination of total transfer capability 
for the on-peak and off-peak intra-day and next day time periods, as 
well as days two through 31 and for months two through 13.\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.
---------------------------------------------------------------------------

    \55\ This information includes: expected generation and 
transmission outages, additions, and retirements; load forecasts; 
and unit commitment and dispatch order.
---------------------------------------------------------------------------

    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 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 limit 
\56\ or the value determined in Requirement R2. The transmission 
operator must then provide a transmission service provider with the 
appropriate total transfer capability values and study report within 
seven days of finalization of the study report to be prepared under in 
Requirement R4.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
    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 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.
---------------------------------------------------------------------------

    \57\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 313.

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[[Page 64894]]

    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.
    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 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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \59\ NOPR, FERC Stats. & Regs. ] 32,641 at P 75.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \60\ MOD-001-1, Requirement R3.
---------------------------------------------------------------------------

    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

[[Page 64895]]

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 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).
---------------------------------------------------------------------------

    \61\ NOPR, FERC Stats. & Regs. ] 32,641 at P 81.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \62\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 51.
---------------------------------------------------------------------------

    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 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 calculation 
methodologies being developed by NERC would produce predictable and 
sufficiently accurate, consistent, equivalent and replicable 
results.\64\
---------------------------------------------------------------------------

    \63\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 208.
    \64\ Id. P 210.
---------------------------------------------------------------------------

    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 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\
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    \65\ APPA, Bonneville, Duke, EEI, EPSA, Entegra, FirstEnergy, 
Georgia, ISO/RTO Council, SMUD and NERC.
    \66\ APPA, Bonneville, and ISO/RTO Council.
    \67\ Bonneville, ISO/RTO Council, Joint Municipals, and SMUD.
---------------------------------------------------------------------------

    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.
    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.

[[Page 64896]]

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 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.
---------------------------------------------------------------------------

    \68\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 68.
---------------------------------------------------------------------------

    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 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 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 MOD-030-2. 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 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

[[Page 64897]]

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.
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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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. 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 
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 rather than taking on additional duties to police implementation 
of tariffs and comparability issues.\71\
---------------------------------------------------------------------------

    \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).
    \71\ See also Duke, NYISO and TANC comments.
---------------------------------------------------------------------------

    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

[[Page 64898]]

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 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 approach to available transfer capability lies in the 
Commission's concern over discrimination in the provision of 
transmission service, rather than system reliability.\72\
---------------------------------------------------------------------------

    \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.''
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \73\ See infra section III.3.b.ii.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

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

[[Page 64899]]

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 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\
---------------------------------------------------------------------------

    \76\ Order No. 672, FERC Stats. & Regs. ] 31,204 at P 332.
    \77\ Id.
    \78\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 195.
---------------------------------------------------------------------------

    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.
    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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 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 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.
---------------------------------------------------------------------------

    \80\ E.g., APPA, Cottonwood, EEI, EPSA, NRU, Pacific Northwest, 
Public Power Council, Puget Sound, Joint Municipals and Snohomish.
---------------------------------------------------------------------------

    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

[[Page 64900]]

transmission operators have failed to fully comply with transparency 
obligations. Puget Sound states that the Commission has an established 
method to 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.
---------------------------------------------------------------------------

    \81\ E.g., Cottonwood, EEI, EPSA, Puget Sound, TAPS and TANC.
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \82\ E.g., Entegra, EPSA, the Georgia Companies, ITC Companies, 
NYISO, and Puget Sound.
---------------------------------------------------------------------------

    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 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 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 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.
---------------------------------------------------------------------------

    \83\ E.g., APPA, Bonneville, ColumbiaGrid, Georgia Companies, 
TANC and TAPS.
---------------------------------------------------------------------------

    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

[[Page 64901]]

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 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 market-related 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.
    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.
    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\
---------------------------------------------------------------------------

    \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. Sec.  2462 (2000)).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \85\ See Standards for Business Practices and Communication 
Protocols for Public Utilities, Order No. 676-E, 129 FERC ] 61,162 
(2009).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \86\ The Commission does not anticipate allowing an opportunity 
for public comment on the filed audit reports.
---------------------------------------------------------------------------

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

[[Page 64902]]

offer the appropriate level of discretion in the calculation of the 
various parameters including the 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 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 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 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 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.
---------------------------------------------------------------------------

    \87\ NOPR, FERC Stats. & Regs. ] 32,641 at P 104.
---------------------------------------------------------------------------

    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

[[Page 64903]]

necessary to improve access by transmission customers to the 
implementation documents.
---------------------------------------------------------------------------

    \88\ Id. P 105.
---------------------------------------------------------------------------

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 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 Bulk-Power 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 
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.
---------------------------------------------------------------------------

    \89\ E.g., APPA, Bonneville, Duke, EEI, the Georgia Companies, 
ISO/RTO Council, Pacific Northwest, SMUD, Snohomish, TANC.
    \90\ E.g., Bonneville, EEI, SMUD, Snohomish, Salt River.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \91\ E.g., APPA, Bonneville, ColumbiaGrid, ISO/RTO Council, 
Pacific Northwest, SMUD, Snohomish, Salt River.
---------------------------------------------------------------------------

    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 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 non-disclosure 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.
    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 Reliability 
Standards

[[Page 64904]]

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 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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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 
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. 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.
    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

[[Page 64905]]

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 cannot 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.
---------------------------------------------------------------------------

    \93\ Citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 
254.
---------------------------------------------------------------------------

    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 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 
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.
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.
---------------------------------------------------------------------------

    \94\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 51.
---------------------------------------------------------------------------

    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 
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.
---------------------------------------------------------------------------

    \95\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 245; Order 
No. 693, FERC Stats. & Regs. ] 31,242 at P 1033.
    \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.
---------------------------------------------------------------------------

    161. Nevertheless, the Commission believes that these Reliability 
Standards

[[Page 64906]]

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 
over-estimate available transfer or flowgate capability, adjacent 
systems will be unable to effectively model their own transfer or 
flowgate capabilities, thus resulting in a degradation to the reliable 
operation of the Bulk-Power System.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \98\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 290.
    \99\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 99.
---------------------------------------------------------------------------

    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 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 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. 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

[[Page 64907]]

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 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 to how network resource is to 
be modeled to avoid confusion.
---------------------------------------------------------------------------

    \100\ Citing NOPR, FERC Stats. & Regs. ] 32,641 at P 120.
---------------------------------------------------------------------------

    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 unit-specific 
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 pro-competitive 
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 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 to run, as they are 
expected to run, and to address the effect on available transfer 
capability of designating and undesignating a network resource.
---------------------------------------------------------------------------

    \101\ See Order No. 693, FERC Stats. & Regs. ] 31,242 at P 119.
---------------------------------------------------------------------------

    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 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 MOD-029-1 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

[[Page 64908]]

version of those Reliability Standards. As NERC considers modification 
to these standards, TAPS may participate in the standards development 
process to address its concerns regarding the treatment of unit-
specific network resource undesignations on the calculation of 
available transfer capability.\102\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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 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 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 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.
---------------------------------------------------------------------------

    \103\ NOPR, FERC Stats. & Regs. ] 32,641 at P 107.
---------------------------------------------------------------------------

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 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

[[Page 64909]]

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.
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.
---------------------------------------------------------------------------

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 sub-requirements: 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 MOD-001-1. 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.
    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 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\
---------------------------------------------------------------------------

    \105\ Citing Order No. 672, FERC Stats. & Regs. ] 31,204 at P 
329.
---------------------------------------------------------------------------

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''

[[Page 64910]]

period and the next 12 months as months 2 through 13.
    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 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 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 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.
---------------------------------------------------------------------------

    \106\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 292.
    \107\ Citing Order No. 693, FERC Stats. & Regs. ] 31,242 at P 
758.
---------------------------------------------------------------------------

    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 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

[[Page 64911]]

available flowgate capability and total transfer capability or total 
flowgate capability models and calculations.
---------------------------------------------------------------------------

    \108\ Citing Id. P 1057; Order No. 890, FERC Stats. & Regs. ] 
31,241 at P 292.
---------------------------------------------------------------------------

    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.
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.
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 
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.
---------------------------------------------------------------------------

    \109\ Citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 
310.
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

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

[[Page 64912]]

transfer capability.\111\ The Commission noted, in the NOPR, that the 
MOD Reliability Standards achieve consistency by requiring each 
transmission service provider to identify in its available transfer 
capability implementation document how it accounts for counterflows and 
to calculate available transfer capability using assumptions no more 
limiting than those used in the planning of operations for the 
corresponding time period.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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 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 sub-requirement 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, 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.
    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

[[Page 64913]]

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.
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 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 over-reservation of capacity benefit margin, considering 
the scant likelihood of actual impairment of the reliability of the 
system. Midwest ISO contends that the benefit to system reliability 
that would result from setting aside capacity benefit margin for a low-
probability 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 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.

[[Page 64914]]

    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 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 MOD-008-1 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.
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.
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 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.

[[Page 64915]]

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 sub-
requirement R2.2 pursuant to its Reliability Standards development 
process to clarify the phrase ``adjacent and beyond Reliability 
Coordination areas.''
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 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 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 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 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 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 are 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.
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

[[Page 64916]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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 Rating \115\ 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 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\
---------------------------------------------------------------------------

    \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.
    \117\ E.g., Avista, LADWP, Modest, Salt River, SWAT, TANC, and 
Tucson.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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.

[[Page 64917]]

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, 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, MOD-028-1, 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 sub-requirements 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.
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 calendar days of the notification if it is notified of a 
change in the rating by the 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.
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 resolved, 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 recalculates 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 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.

[[Page 64918]]

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 scheduled including roll-over rights, the impact of any 
grandfathered firm obligation expected to 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 providers do 
not overstate the capacity set aside for existing transmission 
commitment 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 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 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.
---------------------------------------------------------------------------

    \119\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 244.
    \120\ Id.
---------------------------------------------------------------------------

    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 non-firm 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 
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

[[Page 64919]]

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.
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 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 sub-requirements 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 and contains modeling data and system topology 
(or equivalent representation) for immediately adjacent and beyond 
reliability coordination areas. When calculation available flowgate 
capabilities, sub-requirement 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 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.
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 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-

[[Page 64920]]

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 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 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.
---------------------------------------------------------------------------

    \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).
    \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).
---------------------------------------------------------------------------

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 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.''
---------------------------------------------------------------------------

    \123\ Citing Violation Risk Factor Order, 119 FERC ] 61,145 at P 
9.
---------------------------------------------------------------------------

    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 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).

---------------------------------------------------------------------------

[[Page 64921]]

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.
---------------------------------------------------------------------------

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 FAC-012-1, 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 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.
---------------------------------------------------------------------------

    \126\ NOPR, FERC Stats. & Regs. ] 32,641 at P 138.
    \127\ See MOD-001-1, Requirement R2.3.
---------------------------------------------------------------------------

    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 
that takes account of the need for consistency in the criteria used to 
calculate transfer capabilities.\130\
---------------------------------------------------------------------------

    \128\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 777.
    \129\ Id. P 782.
    \130\ Id. P 779, 782.
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \131\ Citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 
323 and Attachment C.
---------------------------------------------------------------------------

    282. EEI further contends that there is no reliability concern 
created by retiring FAC-012-1 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.

[[Page 64922]]

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 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 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 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.
---------------------------------------------------------------------------

    \132\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1047.
---------------------------------------------------------------------------

    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 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 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

[[Page 64923]]

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 sub-requirement R1.2 of TPL-005. The 
Commission believes that this definition should be consistent 
throughout the Reliability Standards.
---------------------------------------------------------------------------

    \133\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 782.
    \134\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 323.
---------------------------------------------------------------------------

    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.
    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. 693 
\135\ 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.
---------------------------------------------------------------------------

    \135\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 779, 782.
---------------------------------------------------------------------------

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 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.
    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, 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

[[Page 64924]]

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 Standards should take into 
consideration regional differences such as those highlighted by 
commenters.
---------------------------------------------------------------------------

    \136\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 5.
    \137\ Id. P 6.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \138\ See id. P 254.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \139\ See 18 CFR 37.6(b)(1).
---------------------------------------------------------------------------

    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 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 FPA \140\ and 18 CFR 39.1 (2008), to be included 
in the NERC Glossary.
---------------------------------------------------------------------------

    \140\ 16 U.S.C. 824o.
---------------------------------------------------------------------------

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 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 Sec.  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

[[Page 64925]]

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 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 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 
final 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\
---------------------------------------------------------------------------

    \141\ 44 U.S.C. 3507(d).
    \142\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \143\ These burden estimates apply only to this Final Rule and 
do not reflect upon all of FERC-516 or FERC-717.

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          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.
    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

[[Page 64926]]

Director, Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: 
[email protected].].
    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 Energy 
Regulatory Commission, phone (202) 395-4650, fax: (202) 395-7285, e-
mail: [email protected].].

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\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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 the transmission 
of electric energy in interstate commerce. Accordingly, these entities 
do not fall typically within the definition of a small entity.\147\
---------------------------------------------------------------------------

    \146\ 5 U.S.C. 601-612.
    \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).
---------------------------------------------------------------------------

    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 Final Rule will not have a significant economic 
impact on a substantial number of small entities. Accordingly, no 
regulatory flexibility analysis is required.
---------------------------------------------------------------------------

    \148\ Id.
---------------------------------------------------------------------------

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 p.m. 
Eastern time) at 888 First Street, NE., 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 Web 
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
[email protected].

VIII. Effective Date and Congressional Notification

    320. These regulations are effective February 8, 2010. The 
Commission notes that although the determinations made in this Final 
Rule are effective February 8, 2010, 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.

    By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

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.

[[Page 64927]]

 
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.
TAPS..............................................  Transmission Access
                                                     Policy Study Group.
TANC..............................................  Transmission Agency
                                                     of Northern
                                                     California.
Tucson............................................  Tucson Electric
                                                     Power Company.
------------------------------------------------------------------------

[FR Doc. E9-28620 Filed 12-7-09; 8:45 am]
BILLING CODE P