[Federal Register: January 16, 2008 (Volume 73, Number 11)]
[Rules and Regulations]
[Page 2983-3143]
[DOCID:fr16ja08-17]

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Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 37

Preventing Undue Discrimination and Preference in Transmission Service;
Final Rule

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 37

[Docket Nos. RM05-17-001, 002 and RM05-25-001, 002; Order No. 890-A]

Preventing Undue Discrimination and Preference in Transmission
Service

Issued December 28, 2007.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Order on rehearing and clarification.

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SUMMARY: The Federal Energy Regulatory Commission affirms its basic
determinations in Order No. 890, granting rehearing and clarification
regarding certain revisions to its regulations and the pro forma open-
access transmission tariff, or OATT, adopted in Order Nos. 888 and 889
to ensure that transmission services are provided on a basis that is
just, reasonable, and not unduly discriminatory. The reforms affirmed
in this order are designed to: (1) Strengthen the pro forma OATT to
ensure that it achieves its original purpose of remedying undue
discrimination; (2) provide greater specificity to reduce opportunities
for undue discrimination and facilitate the Commission's enforcement;
and (3) increase transparency in the rules applicable to planning and
use of the transmission system.

DATES: Effective Date: This rule will become effective March 17, 2008.

FOR FURTHER INFORMATION CONTACT:
    W. Mason Emnett (Legal Information), Office of the General
Counsel--Energy Markets, Federal Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426,<PHONE_NUMBER>.
    Daniel Hedberg (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426,<PHONE_NUMBER>.
    Tony Ingram (Technical Information), Office of Energy Market
Regulation, 888 First Street, NE., Washington, DC 20426, (202) 502-
8938.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction
II. Need for and Applicability of Order No. 888
    A. The Need for Reform
    B. Core Elements of Order No. 888 That Are Retained
    C. Scope and Applicability of Order No. 890
III. Reforms of the OATT
    A. Consistency and Transparency of ATC Calculations
    B. Coordinated, Open, and Transparent Planning
    C. Transmission Pricing
    1. Energy and Generation Imbalances
    2. Credits for Network Customers
    3. Capacity Reassignment
    4. ``Operational'' Penalties
    5. ``Higher of'' Pricing Policy
    6. Other Ancillary Services
    D. Non-Rate Terms and Conditions
    1. Modifications to Long-Term Firm Point-to-Point Service
    2. Rollover Rights
    3. Modification of Receipt or Delivery Points
    4. Acquisition of Transmission Service
    5. Designation of Network Resources
    6. Clarifications Related to Network Service
    7. Transmission Curtailments
    8. Standardization of Rules and Practices
    9. OATT Definitions
    E. Enforcement
IV. Information Collection Statement
V. Document Availability
VI. Effective Date and Congressional Notification
Regulatory Text
Appendix A: Petitioner Acronyms
Appendix B: Post-Technical Conference Commenter Acronyms
Appendix C: Pro Forma Open Access Transmission Tariff

    Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G.
Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

I. Introduction

    1. On February 16, 2007, the Commission issued Order No. 890,\1\
addressing and remedying opportunities for undue discrimination under
the pro forma Open Access Transmission Tariff (OATT) adopted in Order
No. 888.\2\ The pro forma OATT was intended to foster greater
competition in wholesale power markets by reducing barriers to entry in
the provision of transmission service. In the ten years since Order No.
888, however, flaws in the pro forma OATT undermined its ability to
realize the core objective of remedying undue discrimination. The
Commission acted in Order No. 890 to correct these flaws by reforming
the terms and conditions of the pro forma OATT in several critical
areas, including the calculation of available transfer capability
(ATC), the planning of transmission facilities, and the conditions of
services offered by each transmission provider.
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    \1\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, 72 FR 12,266 (March 15, 2007),
FERC Stats. & Regs. ] 31,241 (2007) (Order No. 890).
    \2\ 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-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) (TAPS v. FERC), aff'd
sub nom. New York v. FERC, 535 U.S. 1 (2002).
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    2. Many have expressed support of the Commission's reforms. Greater
specificity regarding the transmission provider's obligations under its
OATT will reduce opportunities for the exercise of undue
discrimination, make undue discrimination easier to detect, and
facilitate the Commission's enforcement of the tariff. Greater
transparency in the rules applicable to the planning and use of the
transmission system will help both transmission providers and customers
comply with applicable tariff requirements. Although we grant rehearing
and clarification below to address certain implementation issues raised
by petitioners, we leave in place the fundamental reforms adopted in
Order No. 890.
    3. At the outset, we note that work is well underway to develop
consistent practices governing the calculation of ATC, in coordination
with the North American Electric Reliability Corporation (NERC) and the
North American Energy Standards Board (NAESB). Eliminating the broad
discretion that transmission providers currently have in calculating
ATC will increase nondiscriminatory access to the grid and ensure that
customers are treated fairly in seeking alternative power supplies. We
commend transmission providers for the substantial resources they have
dedicated to this process and NERC and NAESB for their leadership in
guiding the standardization effort.
    4. We also commend transmission providers for the substantial
resources dedicated to the development of transmission planning
processes in response to Order No. 890. Transmission providers and
stakeholders recently submitted tariff proposals that will govern
transmission planning under the pro forma OATT. Transmission planning
is critical because it is the means by which customers consider and
access new sources of energy and have an opportunity to explore the
feasibility of non-transmission alternatives. It is therefore vital for
each transmission provider to open its transmission planning process to
customers, coordinate with customers regarding future system plans, and
share necessary planning information with customers.

    5. In addition, transmission providers have implemented new service
options for long-term firm point-to-point customers and adopted
modifications to other services. Instead of denying a long-term request
for point-to-point service because as little as one hour of service is
unavailable, transmission providers must now consider their ability to
offer a modified form of planning redispatch or a new conditional firm
option to accommodate the request. This increases opportunities to
efficiently utilize transmission by eliminating artificial barriers to
use of the grid. Charges for energy and generation imbalances also have
been standardized, including relaxed penalties for intermittent
resources. This standardization reduces the potential for undue
discrimination, increases transparency, and reduces confusion in the
industry that resulted from the prior lack of consistency.
    6. Taken together, these and other reforms adopted in Order No. 890
will better enable the pro forma OATT to achieve the core object of
remedying undue discrimination in the provision of transmission
service. The Commission therefore rejects requests to eliminate, or
substantially modify, the various reforms adopted in Order No. 890.\3\
We address each of the arguments made by petitioners in turn. We also
address comments received in response to the technical conference held
by Commission staff on July 30, 2007, regarding certain issues related
to the designation and termination of network resources, in section
III.D.5.\4\
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    \3\ A list of petitioners filing requests for rehearing and/or
clarification is provided in Appendix A. The requests for rehearing
filed by American Transmission, Bonneville, EPSA, Pacific Northwest
Parties, and REPIO are deficient because they fail to include a
Statement of Issues section separate from the arguments made, as
required by Rule 713 of the Commission's Rules of Practice and
Procedure. See 18 CFR 385.713(c)(2). Consistent with Rule 713, we
deem these petitioners to have waived the particular issues for
which they seek rehearing. We also reject TranServ's request for
rehearing for having been filed late, in violation of section 313(a)
of the Federal Power Act (FPA). See 16 U.S.C. 8351(a). The
Commission does consider, however, these petitioners' requests for
clarification, to the extent they are not in fact requests for
rehearing. We also address the merits of each request for rehearing
to demonstrate that, had they been considered, our decision would be
unchanged.
    \4\ A list of parties filing comments in response to the July
30, 2007 technical conference is provided in Appendix B.
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II. Need for and Applicability of Order No. 888

 A. The Need for Reform

    7. As the Commission noted in Order No. 888, it is in the economic
self-interest of transmission monopolists to deny transmission to
competitors or to offer transmission on a basis that is inferior to
that which they provide themselves.\5\ The Commission sought to remedy
that potential for discrimination through adoption of the pro forma
OATT in Order No. 888. Despite the many accomplishments of Order No.
888, the Commission determined in Order No. 890 that the existing pro
forma OATT continued to allow transmission providers substantial
discretion in implementing some of its basic requirements. This
discretion, in turn, created substantial opportunities for undue
discrimination. Order No. 890 reformed the pro forma OATT to limit
opportunities for undue discrimination and promote efficient use of the
grid.
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    \5\ Order No. 888 at 31,682.
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    8. In Order No. 890, the Commission rejected arguments that it was
relying on unsubstantiated allegations of discriminatory conduct to
justify its reforms. Although certain commenters did allege
discriminatory conduct in response to the Notice of Proposed Rulemaking
(NOPR) initiating this proceeding,\6\ the Commission made clear that it
was not making specific factual findings of discrimination and that
such specific findings were not required in order for it to promulgate
a generic rule to eliminate undue discrimination.\7\ The Commission
explained that it had ample grounds to act as necessary to limit
opportunities for undue discrimination that continue to exist under the
pro forma OATT.
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    \6\ Preventing Undue Discrimination and Preference in
Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,636
(Jun. 6, 2006), FERC Stats. & Regs. ] 32,603 (2006) (NOPR).
    \7\ See Order No. 890 at P 41 (citing 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); National Fuel Gas Supply Corp
v. FERC, 468 F.3d 831 (D.C. Cir. 2006)).
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Requests for Rehearing and Clarification
    9. Many petitioners agree with the Commission on rehearing that
reforms to the pro forma OATT are needed because there continues to be
both the opportunity and incentive for transmission providers to engage
in undue discrimination.\8\ Two petitioners, however, seek rehearing of
that finding as sufficient justification for adopting the reforms set
forth in Order No. 890.
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    \8\ See e.g., Constellation, MISO, NRECA, Powerex, PSEG, and
TAPS.
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    10. E.ON U.S. argues that the Commission has not presented any
actual evidence of discrimination or opportunities for undue
discrimination. Without actual evidence of discrimination, E.ON U.S.
argues that the Commission lacks reasoned support for its finding that
the reforms adopted in Order No. 890 are necessary to remedy undue
discrimination. E.ON U.S. states a particular concern for the cost of
implementing these reforms. E.ON U.S. contends that, absent evidence of
unduly discriminatory behavior, the burdensome nature of compliance
with Order No. 890 outweighs the benefits of its reforms.
    11. Southern expresses similar concern that Order No. 890 lacks
actual findings of discrimination. Southern claims that the theoretical
claims of discrimination relied upon by the Commission are attenuated
and inconsistent with statements discouraging commenters from making
sweeping generalizations regarding undue discrimination. Rather than
predicating Order No. 890 on the Commission's authority to prevent
undue discrimination, Southern suggests that the Commission clarify
that it is promulgating these reforms pursuant to its authority to
ensure just and reasonable rates and not to prevent undue
discrimination.
    12. Southern also argues that the Commission failed to acknowledge
other legal requirements and processes adopted after issuance of Order
No. 888 that mitigate a transmission provider's incentives to
discriminate, such as the Standards of Conduct, enforcement audits, new
civil penalty authority, and mandatory reliability standards. Southern
contends that transmission providers have a pecuniary incentive to
grant, rather than deny, customer requests since doing so provides
additional OATT revenues. Southern argues that the Commission appears
to equate discretion with opportunities for discrimination, yet in
certain circumstances expressly acknowledges that the transmission
provider retains discretion in certain activities.
Commission Determination
    13. The Commission concluded in Order No. 890 that reforms to the
pro forma OATT were necessary to address remaining opportunities for
undue discrimination by transmission providers. Despite the efforts of
Order No. 888 and our subsequent reforms, including those cited by
Southern, opportunities for undue discrimination continued to exist.
Under section 206 of the FPA, the Commission has a continuing
obligation to ``determine whether any rule, regulation, practice or
contract affecting rates for such transmission or sale for resale is
unduly discriminatory or preferential, and must prevent those contracts
and practices

that do no meet this standard.'' \9\ The Commission's finding that
continuing opportunities to discriminate exist therefore supports our
action under FPA section 206 to adopt changes to the pro forma OATT.
Upon review of the extensive record of this proceeding, including the
support of a vast majority of commenters, the Commission remains
convinced that the particular reforms adopted in Order No. 890 are
appropriate to satisfy our obligation to remedy undue discrimination.
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    \9\ Order No. 888 at 31,669.
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    14. We reject E.ON U.S.' arguments that, without actual evidence of
undue discrimination, Order No. 890 lacks reasoned support. As the
Commission explained in Order No. 890, the courts have made clear that
the Commission need not make specific factual findings of
discrimination in order to promulgate a generic rule to eliminate undue
discrimination. In Associated Gas Distributors v. FERC, the D.C.
Circuit Court explained that the promulgation of generic rate criteria
involves the determination of policy goals and the selection of the
means to achieve them.\10\ The court concluded that, just as courts do
not insist on empirical data for every proposition upon which the
selection depends, ``[a]gencies do not need to conduct experiments in
order to rely on the prediction that an unsupported stone will fall.''
\11\ The Commission exercised this authority in Order No. 890,
discussing with particularity the concerns motivating each of the
reforms adopted. As it did in Order No. 888, the Commission properly
acted to limit continuing opportunities for undue discrimination, not
to remedy actual instances of undue discrimination.
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    \10\ 824 F.2d 981 (D.C. Cir. 1987).
    \11\ Id. at 1008.
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    15. We acknowledge, as argued by Southern, that it is appropriate
for transmission providers to retain discretion in some areas and that
such discretion does not necessarily equate to discrimination. It is
also true that some OATT revenues may increase as requests for service
are granted (such as for point-to-point requests), rather than denied.
This is not always or even predominantly the case, however, given that
rates for network service are based on load-ratio shares and revenues
do not increase with designations of network resources unless new
facilities are constructed. Moreover, there are competing incentives
for a transmission provider to deny or restrict service to customers in
certain circumstances and allowing broad discretion in such areas is no
longer appropriate. The Commission identified these areas in Order No.
890, including the calculation of ATC, planning for transmission needs,
and the provision of certain transmission services, and acted to remedy
potential discrimination in each area. Notwithstanding the other legal
requirements and processes cited by Southern, the Commission concluded
in Order No. 890 that the reforms adopted were necessary based on a
decade of experience administering the pro forma OATT. While the
Standards of Conduct, audit procedures, and enhanced authority under
the Energy Policy Act of 2005 (EPAct 2005) \12\ have aided the
Commission in fulfilling its obligations under the FPA, the reforms
adopted in Order No. 890 are also necessary to reduce opportunities for
the exercise of undue discrimination, make undue discrimination easier
to detect, and facilitate the Commission's enforcement of the open
access requirements.
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    \12\ Pub. L. No. 109-58, 119 Stat. 594 (to be codified in
scattered titles of the U.S.C.).
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    16. We appreciate that a significant amount of resources must be
dedicated to implementation of the reforms adopted in Order No. 890 by
transmission providers. We believe the burden of implementing these
reforms is fully justified by the need to eliminate remaining
opportunities for undue discrimination in the administration and
implementation of open access requirements under the pro forma OATT. We
note, moreover, that these reforms will benefit transmission providers
seeking to comply with our regulations in good faith by providing more
clarity regarding the requirements of the pro forma OATT previously
left open to interpretation, thereby decreasing the possibility of
disputes with transmission customers and enforcement actions by the
Commission. The ability of transmission customers to misuse the tariffs
to their own advantage, particularly in the scheduling process, has
similarly been addressed. Taken together, we conclude that the benefits
of our reforms outweigh the associated costs of implementation.

B. Core Elements of Order No. 888 That Are Retained

    17. Although Order No. 890 introduced many important reforms, the
Commission also retained many core elements from Order No. 888. As
noted in the NOPR, many provisions of Order No. 888 enjoy broad support
from many sectors of the industry and the Commission did not intend in
this proceeding to pursue the same level of industry restructuring
undertaken there. Rather, the Commission intended Order No. 890 to
strengthen the pro forma OATT while retaining the fundamental structure
articulated in Order No. 888.
    18. The Commission thus retained the existing boundaries between
wholesale and retail service drawn in Order No. 888. The Commission
also retained the native load priority established in Order No. 888.
The Commission stated that this priority continues to strike the
appropriate balance between the transmission provider's need to meet
its native load obligations and the needs of other entities to obtain
service from the transmission provider to meet their own obligations.
Order No. 890 also did not alter the types of services required under
Order No. 888, i.e., network service and point-to-point service.
Finally, the Commission retained the functional unbundling requirement
promulgated in Order No. 888.
Requests for Rehearing and Clarification
    19. South Carolina E&G objects to the Commission's decision to
retain the native load priority established in Order No. 888, arguing
that FPA section 217 requires further protection for native load
service. South Carolina E&G states that the native load priority
adopted under Order No. 888 was implemented so that all customers,
native load and non-native load, would be entitled to equivalent,
nondiscriminatory service.\13\ South Carolina E&G argues that FPA
section 217(k) now entitles load-serving entities (LSEs) to use their
transmission systems to meet their state-law imposed native load
service obligations and that this entitlement can no longer be deemed
discriminatory under the FPA. To the extent an OATT provision
compromising native load service is grounded in a finding of undue
discrimination, South Carolina E&G argues that it must yield to the
need to meet native load service obligations.
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    \13\ Citing Louisville Gas & Elec. Co., 114 FERC ] 61,282 at P
125 (2006).
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    20. Joined by South Carolina Regulatory Staff, South Carolina E&G
objects in particular to the Commission's decision to retain equal
curtailment priority for all firm service.\14\ These petitioners argue
that requiring transmission providers to curtail service to network and
point-to-point customers on a basis comparable to the curtailment of
service to native load customers unfairly exalts non-native customers
at the expense of the

native load that financed the transmission system. They also contend
the Commission's decision is inconsistent with Northern States Power
Co. v. FERC,\15\ which they argue prohibits mandating comparable
curtailment priority among native load and non-native load services in
the face of a state commission edict requiring a transmission provider
to give its native load top curtailment priority. In their view, this
precedent must be read broadly in light of enactment of FPA section
217(k), which they contend peremptorily counters any argument that
priority for native load would be discriminatory.
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    \14\ South Carolina E&G and South Carolina Regulatory Staff also
argue that reforms related to planning redispatch and conditional
firm, rollover rights, and capacity reassignment are in violation of
FPA section 217. We address those arguments in sections III.D.1,
III.D.2, and III.C.3 respectively.
    \15\ 176 F.3d 1090 (8th Cir. 1999).
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    21. E.ON LSE similarly argues that FPA section 217 categorically
protects an LSE's use of firm transmission service to the extent that
such transmission service is required to meet the LSE's service
obligation. E.ON LSE asks the Commission to allow LSEs to deviate from
the requirements of Order No. 890 in circumstances where, in the LSE's
good faith judgment, compliance would adversely affect the provision of
firm transmission service to native load protected by FPA section 217.
    22. TDU Systems request clarification or rehearing to confirm that
there is no preference under the reformed pro forma OATT for a public
utility transmission provider's native load over the service
obligations of other LSEs that use their transmission system. TDU
Systems argue that section 217(a) of the FPA does not distinguish
between the service obligations of transmission providers and the
service obligations of their load serving customers and, therefore,
neither should the pro forma OATT.
Commission Determination
    23. The Commission affirms the decision to retain the native load
protections embodied in Order No. 888, as enhanced by the reforms
adopted in Order No. 890. In Order No. 888, the Commission gave public
utilities the right to reserve existing transmission capacity needed
for native load growth reasonably forecasted within the utility's
current planning horizon.\16\ The Commission also allowed transmission
providers to restrict rollover rights based on reasonably forecasted
need at the time the contract is executed.\17\ Contrary to petitioner's
assertions, the native load protections affirmed in Order No. 890
satisfy the requirements of FPA section 217. Section 217 applies not
only to distribution utilities providing service to end-users, but also
to electric utilities with long-term contracts to provide service to a
distribution utility.\18\ Congress placed each of these types of
customers on equal footing, regardless of their status as a network or
firm point-to-point customer under the pro forma OATT or a transmission
provider serving its native load. We therefore disagree with
petitioners that section 217 requires the Commission to give top
curtailment priority solely to network customers or the transmission
provider serving native load.
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    \16\ See Order No. 888 at 31,394.
    \17\ See id. at 31,745.
    \18\ See EPAct 2005 sec. 1233(a)(3) (to be codified at section
217(a)(3) of the FPA, 16 U.S.C. 824q(a)(3)). Petitioners' reliance
on Northern States Power Co. v. FERC, 176 F.3d 1090 (8th Cir. 1999),
is therefore misplaced. As the Commission has explained, the court
upheld our authority to require pro rata curtailment of both
network/native load and firm point-to-point service except in the
limited circumstance when it would require the shedding of bundled
retail load. Indeed, FPA section 217 could be read to grant electric
utilities with long-term contracts to provide service to a
distribution utility equal curtailment priority with other LSEs even
in that limited situation, although we decline to address that
argument here as it has not been raised on rehearing.
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    24. We decline to allow LSEs to deviate from the requirements of
the pro forma OATT as they believe necessary to serve their native
load, as suggested by E.ON LSE. Section 217 is intended to facilitate
the ability of all utilities using firm transmission to meet their
long-term service obligations, which the statute defines broadly to
include not only service to end-users, but also distribution utilities
serving end-users.\19\ The requirements of the pro forma OATT and the
reforms adopted in Order No. 890 appropriately balance the needs of
these various classes of transmission customers, including the
transmission provider's native load, LSE customers serving network
load, and other firm users of the system. This is entirely consistent
with, if not expressly required by, FPA section 217.
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    \19\ See EPAct 2005 sec 1233(a) (to be codified at section
217(a) of the FPA, 16 U.S.C. 824q(a)).
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C. Scope and Applicability of Order No. 890

    25. The reforms adopted in Order No. 890 apply to all transmission
providers, including Commission-approved regional transmission
organizations (RTOs) and independent system operators (ISOs), and non-
public utility transmission providers with reciprocity obligations. The
particular process for implementing certain of the reforms adopted in
Order No. 890 varied depending on the type of transmission provider at
issue.
    26. For those transmission providers that have not been approved as
ISOs or RTOs, and whose facilities are not under the control or within
the footprint of an ISO or RTO, Order No. 890 established a two-tiered
compliance process for adopting the non-rate terms and conditions of
the revised pro forma OATT. These transmission providers were directed
to submit FPA section 206 compliance filings that contain the revised
non-rate terms and conditions of the revised pro forma OATT within 60
days after publication of the order in the Federal Register.\20\ Any of
these transmission providers that wished to retain a previously-
approved variation from the Order No. 888 pro forma OATT that was
substantively affected by a reform adopted in Order No. 890 were
directed to submit, within 30 days after publication of Order No. 890
in the Federal Register, a request under FPA section 205 to retain
those previously-approved variations, provided they continued to be
consistent with or superior to the revised pro forma OATT adopted in
Order No. 890.
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    \20\ The Commission subsequently extended by 60 days the date on
which the reforms adopted in Order No. 890 would have otherwise been
effective. See Preventing Undue Discrimination and Preference in
Transmission Service, 119 FERC ] 61,037 (2007) (April 11 Order).
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    27. ISO and RTO transmission providers were directed to submit FPA
section 206 compliance filings, within 210 days after the publication
of Order No. 890 in the Federal Register, that contain the non-rate
terms and conditions set forth in Order No. 890 or that demonstrate
that their existing tariff provisions are consistent with or superior
to the revised provisions of the pro forma OATT. Transmission-owning
members of ISOs and RTOs, and non-ISO/RTO transmission providers within
the footprint of an ISO or RTO, were similarly directed to make any
necessary tariff filings within 210 days of its publication in the
Federal Register.
    28. With regard to non-public utility transmission providers, the
Commission retained the reciprocity language of the Order No. 888 pro
forma OATT with a few modifications. First, the Commission updated the
language to contain references to ISOs and RTOs, requiring transmission
customers that are members of, or that take service from, an ISO/RTO to
make comparable service available to other members of the ISO/RTO. As
proposed in the NOPR, the Commission did not adopt a generic rule to
implement FPA section 211A, which allows the Commission to require an
unregulated transmitting utility to provide transmission services at
rates that are comparable to those it charges itself and under non-rate
terms and

conditions that are comparable to those it applies to itself, and are
not unduly discriminatory or preferential. The Commission instead
explained that it would follow a case-by-case approach to implementing
FPA section 211A.
Requests for Rehearing and Clarification
    29. Few petitioners question the applicability of Order No. 890,
although some are concerned with the timing of the compliance actions
required by the Commission. Southern asks the Commission to grant
rehearing and extend the initial compliance deadlines by 60 days and to
remain open to further requests for extension if the deadlines set
forth in Order No. 890 cannot be met. MidAmerican asks the Commission
to extend the effective date for the revisions to the pro forma OATT to
the first day of the month following the effective date of these
reforms. MidAmerican contends that it will be burdensome for
transmission providers and confusing to transmission customers to
implement the reforms adopted in Order No. 890 in the middle of a
billing cycle.
    30. TDU Systems express concern with the burden of reviewing
section 205 filings by transmission providers seeking a determination
from the Commission that a previously-approved variation from Order No.
888 continues to be consistent with or superior to the revised pro
forma OATT. TDU Systems contend that reviewing and evaluating these
filings will be a large and time-consuming process. TDU Systems ask the
Commission to allow transmission customers 45 days to perform their own
evaluation and comment upon these filings, while retaining a 90-day
deadline for the Commission to process the filings. Alternatively, TDU
Systems request rehearing of the Commission's decision not to stagger
the due dates for the various compliance filings required in Order No.
890.
    31. Although they recognize that Order No. 890 preserves existing
waivers of the obligations to file an OATT, Unitil and Alcoa seek
explicit confirmation that their waivers of the obligation to maintain
an Open Access Same-Time Information System (OASIS) site are still
valid. Unitil notes that the Commission has found that it does not
operate or control an interstate transmission grid.\21\ In addition,
Unitil states that it voluntarily offers relevant information to ISO-NE
for posting on its OASIS Web site. Similarly, Alcoa notes that the
Commission has granted waiver of OASIS requirements to its Long Sault
division, which owns five transmission lines in northern New York
connecting Alcoa to its electric energy suppliers.\22\ Thus, Unitil and
Alcoa seek confirmation that the Commission did not intend the OASIS
requirements outlined in Order No. 890 to apply to their operations.
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    \21\ Citing Northern States Power Co., 76 FERC ] 61,250 at
62,297 (2002).
    \22\ Citing Alcoa Power Generating, Inc. (Long Sault Division),
116 FERC ] 61,257 (2006).
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    32. NRECA requests clarification, or in the alternative rehearing,
that the Commission did not intend in Order No. 890 to extend
reciprocity obligations beyond transmission owning members of an ISO or
RTO. NRECA contends that the Commission's modification to the pro forma
OATT creates ambiguity by imposing the reciprocity obligation for all
``members'' of an ISO or RTO. NRECA points out that some members of
ISOs and RTOs do not own transmission, such as transmission dependent
utilities, state regulatory authorities and eligible end-use customers.
NRECA argues that expanding the reciprocity obligation to require non-
public utility transmission providers to provide service to non-
transmission owning members of an ISO or RTO would contradict
Commission precedent \23\ and be unsupported by the record in this
proceeding.
---------------------------------------------------------------------------

    \23\ Citing American Transmission Co. LLC, 95 FERC ] 61,387
(2001).
---------------------------------------------------------------------------

    33. WSPP requests that the Commission establish a date by which it
must submit a compliance filing containing the non-rate terms and
conditions of the revised pro forma OATT. WSPP states that it is
neither a transmission provider nor an RTO/ISO and, instead, only has a
limited open access transmission tariff on file with the Commission.
WSPP states that this tariff only applies to its transmission-owning
members that do not otherwise have an OATT.
Commission Determination
    34. In the April 11 Order, the Commission granted requests by EEI
and others to extend by 60 days the date by which transmissions
providers outside of ISO/RTO regions would have to submit compliance
filings containing the non-rate terms and conditions of the revised pro
forma OATT.\24\ Southern's request for rehearing on this point is
therefore moot. Similarly, we reject as unnecessary TDU Systems'
request to allow transmission customers additional time to evaluate and
comment upon compliance filings. These filings have already been made,
comments have been filed, and in many cases orders addressing the
filings have been issued.
---------------------------------------------------------------------------

    \24\ April 11 Order at P 20.
---------------------------------------------------------------------------

    35. The Commission also determined in the April 11 Order that it
would be reasonable for a transmission provider to request that the
imbalance-related provisions in Schedule 4 and Schedule 9 of the pro
forma OATT be made effective on the first day of the billing cycle
following the effectiveness of the underlying imbalance-related
reforms.\25\ MidAmerican does not explain or otherwise justify the need
to delay the effectiveness of any other reforms until the following
billing cycle. We therefore reject as moot MidAmerican's request to
extend the effective date of the imbalance-related reforms adopted in
Order No. 890 until the following billing cycle and reject as
unsupported its request to extend the effective date of all other
reforms adopted in Order No. 890.
---------------------------------------------------------------------------

    \25\ Id. at P 22.
---------------------------------------------------------------------------

    36. The Commission made clear in Order No. 890 that the reforms
therein were not intended to disturb any existing waivers of the
obligation to file an OATT or otherwise offer open access transmission
service.\26\ The criteria for waiver of Order No. 890, moreover,
remains unchanged from that used to evaluate the requests for waiver
under Order Nos. 888 and 889. Revocation of any waivers will continued
to be considered on a case-by-case basis in response to concerns raised
by interested parties. We clarify that this applies equally to existing
waivers of Order No. 889 and requirements to maintain an OASIS site.
---------------------------------------------------------------------------

    \26\ See Order No. 890 at P 135, n.105.
---------------------------------------------------------------------------

    37. We grant rehearing, in response to NRECA, to revise section 6
of the pro forma OATT to require a customer that is a member of or that
takes service from an RTO or ISO to provide comparable service, to the
extent it owns transmission facilities, only to the transmission-owning
members of the RTO or ISO. The Commission has expressed concern in the
past that failure to grant reciprocity to transmission-owning members
of an RTO or ISO would cause those members to lose the right to
reciprocity solely as a result of participating in the RTO or ISO.\27\
We did not intend to expand that obligation in Order No. 890 to other
members of an RTO or ISO when revising the language of section 6 of the
pro forma OATT to refer to RTOs and ISOs.
---------------------------------------------------------------------------

    \27\ See American Transmission Company LLC, 93 FERC ] 61,267 at
61,858-59 (2000), reh'g denied, 95 FERC ] 61,387 at 62,446 (2001).
---------------------------------------------------------------------------

    38. Below the Commission adopts various other revisions to the pro
forma OATT in response to requests for rehearing and clarification.
These revisions do not disturb the

fundamental nature of the reforms adopted in Order No. 890 and, thus,
we do not anticipate any difficulty in their implementation or
disruption in on-going compliance efforts. We direct transmission
providers that have not been approved as RTOs or ISOs, and whose
facilities are not in the footprint of an RTO or ISO, to submit an FPA
section 206 filing that contains the revised non-rate terms and
conditions of the pro forma OATT stated in Appendix C within 60 days of
publication of this order in the Federal Register. We direct RTO and
ISO transmission providers, transmission providers whose facilities are
in the footprint of an RTO or ISO, and WSPP to submit an FPA section
206 filing that contains the revised non-rate terms and conditions of
the pro forma OATT as stated within Appendix C within 90 days of
publication of this order in the Federal Register.

III. Reforms of the OATT

A. Consistency and Transparency of ATC Calculations

    39. In Order No. 890, the Commission concluded that the lack of
consistency and transparency in the methodology for calculating ATC
creates the potential for undue discrimination in the provision of open
access transmission service. To remedy this lack of consistency and
transparency, the Commission directed public utilities, working through
the NERC reliability standards and NAESB business practices development
processes, to produce workable solutions to implement the ATC-related
reforms adopted by the Commission. A number of petitioners seek
rehearing and/or clarification regarding the Commission's ATC-related
rulings, which we address below.
1. Consistency
a. Necessary Degree of Consistency
    40. The Commission required industry-wide consistency of all ATC
components \28\ and certain definitions, data inputs, data exchange,
and modeling assumptions in order to reduce the potential for undue
discrimination in the provision of transmission service. Although the
Commission concluded that the number of industry-wide ATC calculation
formulas should be few in number, it did not require that a single ATC
calculation methodology be applied by all transmission providers. The
Commission found that it is not the methodologies for calculating ATC
that create the opportunity for undue discrimination, rather the
variability in the calculation of the components of ATC and the lack of
a detailed description of the ATC calculation methodology and
underlying assumptions used by the transmission provider.
---------------------------------------------------------------------------

    \28\ The ATC components are total transfer capability (TTC),
existing transmission commitments (ETC), capacity benefit margin
(CBM), and transmission reserve margin (TRM).
---------------------------------------------------------------------------

    41. The Commission noted that NERC was then in the process of
developing standards for three ATC calculation methodologies: contract
or rated path ATC, network ATC, and network Available Flowgate Capacity
(AFC). The Commission concluded that, if all of the ATC components and
certain data inputs and assumptions are consistent, the use of the
three ATC calculation methodologies included in reliability standards
being developed would be acceptable. With regard to network AFC, the
Commission specifically directed public utilities, working through
NERC, to develop an AFC definition and requirements used to identify a
particular set of transmission facilities as a flowgate. However, the
Commission reminded transmission providers that our regulations require
the posting of ATC values associated with a particular path, not AFC
values associated with a flowgate. The Commission therefore directed
public utilities, working through NERC, to develop in the MOD-001
standard a rule to convert AFC into ATC values to be posted by
transmission providers that currently use the flowgate methodology.
    42. The Commission also required further clarification regarding
the calculation algorithms for firm and non-firm ATC. The Commission
directed public utilities, working through NERC, to modify related ATC
standards by implementing the following principles: (1) For firm ATC
calculations, the transmission provider shall account only for firm
commitments; and (2) for non-firm ATC calculations, the transmission
provider shall account for both firm and non-firm commitments,
postbacks of redirected services, unscheduled service, and
counterflows.
Requests for Rehearing and Clarification
    43. Southern requests that the Commission clarify that consistency
in ATC methodologies and CBM and TRM calculations must not take
precedence over reliability and that some transmission provider
discretion is necessary. Southern states that, in several places, Order
No. 890 discusses minimizing transmission provider discretion in order
to achieve consistency.\29\ Southern contends that totally eliminating
this discretion would not allow transmission providers to address
unique system conditions in ATC, CBM, and TRM calculations, which would
impact system reliability. Southern claims that eliminating
transmission provider discretion also would lead to more conservative
modeling, which would likely result in understated amounts of ATC and
an inefficient use of the system.\30\ To the extent making the
treatment of certain ATC parameters or CBM or TRM calculations
consistent would affect reliability, Southern asks that transparency in
the treatment of those parameters and calculations be required, but
that strict consistency not be enforced.
---------------------------------------------------------------------------

    \29\ Citing Order No. 890 at P 207.
    \30\ Southern suggests that one example of when a transmission
provider should have discretion is when modeling long-term firm
transmission service reservation from a combustion turbine
generating facility. Southern argues that, by its nature, such a
generating facility normally will not often run in off-peak times.
During those times, or when there is an impending outage of a
generating facility, Southern argues that the transmission provider
should have the discretion to reflect the operating characteristics
of the generating facility by not including transmission service
from the facility in its model.
---------------------------------------------------------------------------

    44. MidAmerican requests clarification that AFC quantities do not
need to be converted into control area-to-control area path ATC
quantities and that the Commission is not eliminating the coordination
of individual transmission provider service with seams agreements and/
or regional tariff service on flowgates. MidAmerican asks the
Commission to confirm that it is merely intending to require NERC to
define a flowgate ATC quantity which is equal to or related to the
flowgate AFC. MidAmerican contends that transmission customers,
operators, and owners will not benefit from the conversion of flowgate
AFCs into control area-to-control area path ATCs, the elimination of
AFC as a useful transmission commodity, or the elimination of the
coordination of individual provider and regional transmission service
over flowgates. To the extent the Commission feels there is a
comparability benefit for the conversion of AFC to ATC, MidAmerican
requests clarification that providing transmission customers with a
mechanism on OASIS to query/assess the effective ATC on a specific
transmission path over a specific time is sufficient for compliance
with the transmission provider's ATC posting obligation.
    45. E.ON U.S. requests clarification of the requirement that AFC
calculations be converted into ATC for purposes of posting. E.ON U.S.
states that some

RTOs, such as MISO and others, utilize AFC and do not calculate or post
ATC for their systems. Due to interactions with these RTOs, E.ON U.S.
now calculates AFC as well. E.ON requests that the Commission clarify
that if RTOs and their member utilities are granted waivers of the
requirement to calculate and post ATC, in favor of AFC, all
transmission owning utilities in the region should be able to request a
waiver on the same basis. E.ON claims that allowing all transmission-
owning utilities within a region to calculate AFC (instead of ATC) will
result in greater accuracy and consistency within the industry.
    46. Although it does not challenge the Commission's decision not to
require a single, industry-wide ATC calculation method, TDU Systems
claims that the Commission fails to address the situation where
transmission providers on a single interface choose different ATC
calculation methods. TDU Systems argue that transmission providers must
be required to provide consistent ATC values on either side of an
interface. TDU Systems therefore request that adjacent transmission
providers be required to coordinate to provide consistent ATC values
across their common interfaces.
    47. NorthWestern requests that the Commission clarify that the
consistency requirements of Order No. 890 do not prohibit utilities
from reducing transfer capability for the purchase of reliability
services. According to NorthWestern, some transmission providers may
have to acquire various generation-based services, such as load
following and regulation service, in the marketplace in order to meet
reliability criteria. NorthWestern argues that some means should be
allowed for retaining transmission at no cost for such deliveries, even
though they do not meet the strict definition of CBM, since they are
made for reliability reasons and no single user of the system would
otherwise reimburse the transmission provider for the associated costs.
    48. EPSA and Williams request clarification that ATC and AFC
calculations should be determined and posted in real-time, not just as
planning information, and that the transmission provider be required to
post results of its system utilization for ETC. Williams contends that
this would augment the transparency deemed critical to a coherent and
uniform calculation of ATC by enabling interested stakeholders and the
Commission to verify the ATC calculations performed by transmission
providers.
Commission Determination
    49. The Commission affirms the decision in Order No. 890 to require
consistency of all ATC components and certain definitions, data inputs,
data exchange and modeling assumptions. We continue to believe such
consistency is necessary to reduce the potential for undue
discrimination in the provision of transmission service.
    50. We disagree with Southern that increasing consistency with
respect to the determination of ATC is contrary to reliability. Use of
the NERC reliability standards process will, as a matter of course,
guard against any unintended reduction in reliability. Nevertheless, we
agree that reliability standards cannot address every unique system
difference or differences in risk assumptions when modeling expected
flows, which necessitates leaving room for limited discretion on the
part of the transmission provider. We believe that the ATC requirements
in Order No. 890 allow sufficient flexibility so that utilities,
working through NERC/NAESB, can develop ATC standards that continue to
provide reliability and are compatible with all other mandatory
reliability standards or business practices, yet provide discretion
where appropriate. If a transmission provider is faced with unique
system conditions or modeling assumptions related to firm transmission
service reservations\31\ that are not addressed in the ATC-related NERC
reliability standards, it must make them transparent through its
Attachment C filing and the OASIS posting requirements regarding ATC
calculation and modeling approach, studies, models and assumptions and
implement them consistently for all transmission customers.
---------------------------------------------------------------------------

    \31\ Transmission providers use different assumptions related to
the percentage of firm reservations that are actually scheduled and
flow.
---------------------------------------------------------------------------

    51. We deny MidAmerican's request for clarification that AFC values
do not need to be converted into ATC postings of control area-to-
control area path quantities. As the Commission explained in Order No.
890, our regulations require the posting of ATC values associated with
a particular path, not AFC values associated with a flowgate.\32\ The
Commission did not amend that requirement in Order No. 890 and
MidAmerican fails to justify doing so now. To the extent MidAmerican or
its customers find it beneficial also to post AFC, MidAmerican is free
to post both ATC and AFC values. In response to E.ON U.S., however, we
clarify that transmission-owning utilities in an RTO region can request
waiver of the requirement to convert AFC calculations into ATC for
posting purposes in the event the RTO has been granted such a waiver.
---------------------------------------------------------------------------

    \32\ See Order No. 890 at P 211. ATC values must be posted for
control area to control area interconnections, paths for which
service is denied, curtailed or interrupted for more than 24 hours
in the past 12 months, and paths for which a customer requests to
have ATC or TTC posted. See 18 CFR 37.6(b)(1)(i).
---------------------------------------------------------------------------

    52. In response to TDU Systems, we clarify that adjacent
transmission providers must coordinate and exchange data and
assumptions to achieve consistent ATC values on either side of a single
interface. This is applicable to any neighboring transmission providers
no matter whether they use the same or different ATC methodologies. We
note, however, that the anticipated consistency is for available
capability in the same direction across an interface.
    53. We clarify in response to NorthWestern that TRM may be used to
accommodate the procurement of ancillary services used to provide
service under the pro forma OATT. We deny as premature EPSA's and
Williams' requests for clarification regarding the real-time
determination and posting of ATC and AFC values, as well as posting of
utilization of transmission provider's own system ETC. In Order No.
890, the Commission required an exchange of the data both for short and
long-term ATC/AFC calculation that will increase the accuracy of ATC
calculations.\33\ The Commission also required that ATC be recalculated
by all transmission providers on a consistent time interval, and in a
manner that closely reflects the actual topology of the system, load
forecast, interchange schedules, transmission reservations, facility
ratings, and other necessary data, and that NERC/NAESB revise the
related reliability standard and business practices accordingly.\34\
EPSA and William should address their concerns through the NERC and
NAESB processes implementing these requirements.
---------------------------------------------------------------------------

    \33\ See Order No. 890 at P 310.
    \34\ See id. at P 301.
---------------------------------------------------------------------------

b. Process To Achieve Consistency
    54. The Commission directed public utilities, working through NERC
and NAESB, to modify the ATC-related reliability standards and business
practices in accordance with specific direction provided in Order No.
890. The Commission concluded that the NERC reliability standards
development process and the NAESB business standards development
process are the appropriate forums for developing

consistency in ATC calculations. To that end, public utilities were
directed, working through NERC, to modify the ATC-related reliability
standards within 270 days after the publication of Order No. 890 in the
Federal Register, i.e., December 10, 2007. Public utilities were also
directed, working through NAESB, to develop business practices that
complement NERC's new reliability standards within 360 days after the
publication of Order No. 890 in the Federal Register, i.e., March 10,
2008.\35\
---------------------------------------------------------------------------

    \35\ The Commission has since extended these compliance
deadlines to May 9, 2008, and August 7, 2008, respectively. See
Preventing Undue Discrimination and Preference in Transmission
Service, Notice of Extension of Time, Docket Nos. RM05-17-000, et
al. (Dec. 6, 2007).
---------------------------------------------------------------------------

Requests for Rehearing and Clarification
    55. Several petitioners contend that the Commission's direction to
public utilities, working through NERC, to modify standards to meet
specific ATC requirements is tantamount to dictating reliability
standards in violation of FPA section 215.\36\ These petitioners assert
that system reliability will be best maintained if NERC, having been
certified by the Commission as the ERO, is afforded discretion in
creating the necessary reliability standards in the first instance
prior to submission to the Commission for approval consistent with
section 215.\37\ EEI and Southern suggest that the Commission give
guidance and direction to NERC on how standards should be developed,
but not be overly prescriptive. E.ON LSE argues that the Commission
should require, or at least permit, NERC to consolidate its ATC
development process with its ongoing reliability standards process to
develop policies, but should refrain from rewriting any standards
developed through that consolidated process.
---------------------------------------------------------------------------

    \36\ E.g., EEI, E.ON LSE, and Southern.
    \37\ Citing 16 U.S.C. 824o(d)(2) (requiring the Commission to
``give due weight to the technical expertise of the [ERO]'' on
reliability matters).
---------------------------------------------------------------------------

Commission Determination
    56. The Commission affirms the decision in Order No. 890 to rely on
the NERC reliability standards development process, and the NAESB
business practices development process, to achieve a more coherent and
uniform determination of ATC. We disagree that this conflicts with the
Commission's obligations under section 215 of the FPA. In Order No.
693, the Commission exercised its authority under FPA section 215 to
direct the ERO to modify the existing modeling, data, and analysis
(MOD) standards related to ATC calculation, providing guidance
consistent with our requirements in Order No. 890. The Commission
clarified that, where Order No. 693 identified a concern and offered a
specific approach to address the concern, the Commission would consider
an equivalent alternative approach provided that the ERO demonstrated
that the alternative would address the Commission's underlying concern
or goal as efficiently and effectively as the Commission's
proposal.\38\ We believe this provides the appropriate flexibility for
NERC, while ensuring that the Commission act to remedy the potential
for undue discrimination in the calculation of ATC.
---------------------------------------------------------------------------

    \38\ See Mandatory Reliability Standards for the Bulk Power
System, Order No. 693, 72 FR 16,416 (Apr. 4, 2007), FERC Stats. &
Regs. ] 31,242 (2007) (Order No. 693), order on reh'g, 120 FERC ]
61,053 (2007) (Order No. 693-A). Pending completion of the NERC/
NAESB standardization process, each transmission provider must
perform its ATC-related calculations in accordance with the
methodology set forth in Attachment C to its OATT, as revised to
comply with Order No. 890.
---------------------------------------------------------------------------

c. Applicability to ISOs, RTOs, and Non-Public Utility Transmission
Providers
    57. The Commission did not require ISO and RTO transmission
providers to ``rejustify'' existing provisions in their OATTs that are
not affected in a substantive manner by the revisions to the pro forma
OATT in the Final Rule. However, the Commission did require all
transmission providers, including an ISO or RTO, to demonstrate that
variations from the tariff modifications required in Order No. 890
continue to satisfy the consistent with or superior to standard. With
respect to the application of the ATC requirements of Order No. 890,
the Commission noted that ISOs and RTOs would be required to comply
with reliability standards developed under FPA section 215.
Requests for Rehearing and Clarification
    58. Because Order No. 890 did not exempt ISOs/RTOs from the new ATC
standards or curtailment information posting requirements, NYISO asks
the Commission to clarify that NERC and NAESB must develop ATC
standards and curtailment information posting rules that accommodate
ISOs/RTOs. NYISO anticipates that ATC calculations will continue to be
of limited significance within its control area, but acknowledges that
it does calculate ATC at its external interfaces and also uses ATC to
determine the availability of non-firm transmission service, i.e.,
service for customers that do not wish to be exposed to congestion
charges. NYISO states that it, therefore, has an interest and intends
to participate in the NERC and NAESB processes developing new ATC
standards and curtailment information posting requirements.
    59. NYISO contends, however, that stakeholders from traditional
systems will have a greater interest in the development of those rules
and, as a result, that the NERC and NAESB processes may produce rules
that primarily reflect the needs of traditional systems and do not
accommodate ISOs/RTOs that are based upon locational marginal pricing
of transmission. NYISO argues that Order No. 890 requires NERC and
NAESB to develop standards that suit both traditional systems as well
as the ISOs/RTOs that cover more than half of the load in the United
States. NYISO requests that the Commission expressly state its
expectation that the NERC and NAESB processes will produce standards
that fulfill Order No. 890's objectives of transparency and inter-
regional consistency, yet that are sufficiently flexible to work for
ISO/RTO regions.
Commission Determination
    60. Order No. 890 requires NERC and NAESB to develop a single set
of ATC-related standards that will apply to all transmission providers,
including RTOs and ISOs. We understand that the NERC ATC standard
drafting team includes representatives from various industry sectors,
including RTOs/ISOs, and we encourage NYISO to participate in the
standard development process to provide NERC an opportunity to address
its concerns. To the extent NYISO feels its concerns are not addressed
in this process, it should bring the issue to the Commission's
attention on review of the resulting reliability standards.
d. ATC Components
    61. In Order No. 890, the Commission adopted certain requirements
regarding the components of ATC (i.e., TTC/TFC, ETC, CBM and TRM)
necessary to achieve consistency and, in turn, limit the potential for
undue discrimination in the calculation of ATC. Petitioners request
rehearing and clarification of the Commission's determinations related
to ETC, CBM and TRM, which we address in turn.
(1) ETC
    62. The Commission adopted the NOPR proposal and directed public
utilities, working through NERC and NAESB, to develop a consistent
approach for determining the amount of transfer capability a
transmission provider may set aside for its native load and other
committed uses. The Commission determined that ETC 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,\39\ (4) rollover rights
associated with long-term firm service, and (5) other uses identified
through the NERC process. The Commission determined that ETC should not
be used to set aside transfer capability for any type of planning or
contingency reserve, which are to be addressed through CBM and TRM.\40\
In addition, for short-term ATC calculations, all reserved but unused
transfer capability (non-scheduled) must be released as non-firm ATC.
---------------------------------------------------------------------------

    \39\ The Commission explained that the reference to
``appropriate point-to-point reservations'' meant that reservations
accounted for under ETC depend on the firmness and duration of the
reservation. The Commission stated that the specific characteristics
should be developed in the reliability standard.
    \40\ TRM also includes such things as loop flow and parallel
path flow.
---------------------------------------------------------------------------

    63. The Commission also found that inclusion of all requests for
transmission service in ETC would likely overstate usage of the system
and understate ATC. The Commission therefore found that reservations
that have the same point of receipt (POR) (generator) but different
point of delivery (POD) (load), for the same time frame, should not be
modeled in the ETC calculation simultaneously if their combined
reserved transmission capacity exceeds the generator's nameplate
capacity at the POR. The Commission directed public utilities, working
through NERC, to develop requirements in MOD-001 that lay out clear
instructions on how these reservations should be modeled. The
Commission also concluded that some elements of ETC are candidates for
business practices instead of reliability standards and directed public
utilities, working through NAESB, to develop business practices
necessary for full implementation of the MOD-001 reliability standard.
Requests for Rehearing and Clarification
    64. TDU Systems contend that, although the Commission defined the
ETC component of ATC to include committed uses of the transmission
system, it did not clearly identify how requests for transmission
service are to be treated. TDU Systems question whether the
Commission's use of the term ``committed requests'' is the same as
``confirmed requests'' for service. In order to provide greater
clarity, certainty and transparency to the ATC calculation process, TDU
Systems ask the Commission to clarify that ``committed requests'' means
the same thing as ``confirmed requests,'' as this term is generally
understood throughout the industry.
    65. TranServ requests clarification that the Commission's statement
that all reserved but unused transfer capability (non-scheduled) shall
be released as non-firm ATC was limited to the release of unscheduled
firm transmission capability and not intended to require transmission
providers to release unscheduled non-firm capability for additional
non-firm sales.\41\
---------------------------------------------------------------------------

    \41\ Citing Order No. 890 at 244, 389.
---------------------------------------------------------------------------

Commission Determination
    66. The Commission clarifies in response to TDU Systems' request
that the reference to ``committed requests'' in Order No. 890 was
intended to refer to confirmed transmission service requests. Once a
service request has been approved by the transmission provider and
confirmed by the transmission customer, it should be taken into account
when determining ETC.
    67. We also agree with TranServ that the Commission's reference to
releasing unused (non-scheduled) transfer capability as non-firm ATC
applies to unscheduled firm transmission capability, since all unused
non-firm capacity is deemed available to any entity meeting the
scheduling requirements. This does not alter the requirement that the
transmission provider offer all available capacity, firm or non-firm,
as applicable, consistent with our longstanding open access principles.
(2) CBM
    68. The Commission directed public utilities, working through NERC
and NAESB, to develop clear standards and business practices for how
the CBM value is determined, allocated across transmission paths and
flowgates, and used. To ensure that CBM is used for its intended
purpose, the Commission provided that CBM shall only be used to allow
an LSE to meet its generation reliability criteria. The Commission
rejected requests to allow CBM to be used to meet reserve-sharing
needs, explaining that TRM is the appropriate category for that
purpose. Public utilities were directed to work with NAESB to develop
an OASIS mechanism that will allow for auditing of CBM usage.
    69. The Commission clarified that each LSE within a transmission
provider's control area has the right to request the transmission
provider to set aside transfer capability as CBM for the LSE to meet
its historical, state, RTO, or regional generation reliability criteria
requirement such as reserve margin, loss of load probability, the loss
of largest units, etc. It also determined that LSEs should be permitted
to call for the use of CBM, pursuant to conditions established in the
reliability standards development process. Public utilities were
directed to work through NERC to modify the CBM-related standards to
specify the generation deficiency conditions during which an LSE will
be allowed to use the transfer capability reserved as CBM. The
Commission also directed public utilities, working through NERC, to
develop clear requirements for allocating CBM to paths and flowgates
and concluded that transmission capacity set aside as CBM shall be zero
in non-firm ATC calculations.
    70. Finally, the Commission required the transmission provider to
design their transmission charges so that the class of customers not
benefiting from the CBM set-aside, i.e., point-to-point customers, do
not pay a transmission charge that includes the cost of the CBM set-
aside. Transmission providers were permitted to submit redesigned
transmission charges that reflect the CBM set-aside through a limited
issue FPA section 205 rate filing. The Commission noted that these
filings may be limited to the rate design change only, i.e., they would
not require the submission of cost of service data or a revision to the
transmission provider's revenue requirement.
Requests for Rehearing and Clarification
    71. Duke requests that the Commission clarify that utilities that
do not reserve CBM for themselves do not need to make it available to
others. Although the Commission required transmission providers to make
CBM available to LSEs that request it, Duke argues that the Commission
has no authority under FPA section 206 to require transmission
providers to do so when they do not use CBM themselves since there is
no potential for undue discrimination.
    72. With regard to the calculation of CBM, Southern argues that
requiring a consistent calculation methodology would be harmful to LSEs
because reserve needs vary from area to area. Southern contends that
LSEs should be allowed the flexibility to establish CBM on a per-
interface basis so that CBM use will be commensurate with expected
system conditions, topography, and available capacity markets. Southern
states, for example, that small LSEs typically have fewer internal
resources than larger LSEs and therefore need

more CBM. Southern contends that a consistent methodology could result
in higher infrastructure cost, place system reliability at risk, and
ultimately remove the economic benefit associated with CBM.
    73. Southern also argues that development of a ``one-size-fits
all'' methodology for the calculation of CBM would be impossible due to
varying regional and state mandates governing generation adequacy
issues. Southern contends that such a mandate, if applied to a
transmission provider's native load customers that are under varying
regional and state resource adequacy requirements, would amount to a
regulation of reserve adequacy which is outside of the Commission's
jurisdiction. Southern adds that this would implicate (and may violate)
the reliability provisions of FPA section 215 and the native load
protections of FPA section 217.
    74. TDU Systems request that the Commission clarify, or grant
rehearing, that if a transmission provider does not accommodate
reserve-sharing arrangements for its load-serving transmission
customers as TRM, then it must allow access to the CBM set-aside for
reserve-sharing purposes. TDU Systems are concerned that some
transmission providers do not use TRM set-asides, but rather use a CBM-
approach to reserving capacity across interfaces for reserve-sharing
arrangements. In such cases, TDU Systems state that LSEs needing access
to interface capacity to accommodate reserve-sharing arrangements may
not be able to obtain that capacity if the Commission limits such usage
to TRM. TDU Systems contend that transmission providers set aside
interface capacity to serve their retail native load in the case of
both generation emergencies and economic transactions and that
comparability demands the same for the reserve-sharing arrangements for
LSEs.
    75. With regard to cost recovery of the CBM set-aside, Southern
argues that CBM is a component of network service that is already paid
for by network customers and native load through their bearing a load-
ratio share responsibility for the costs of the transmission system.
Southern contends that CBM is used as a network reservation of
resources used to service network and/or native load under certain
conditions. Southern argues that a network customer's cost
responsibility is based upon its load, not its designation of network
resources and, therefore, the network customer is already bearing CBM-
related costs through its load ratio share responsibility.
    76. As a result, Southern concludes that point-to-point customers
are not paying for CBM capacity and, instead, are paying their
appropriate share of the total transmission system cost based upon
their reservations of capacity. Southern states that Commission policy
requires network customers and native load to bear the costs of both
the capacity they use and any capacity that is not reserved by point-
to-point customers.\42\ Southern argues that the Commission's finding
in Order No. 890 that point-to-point customers are inappropriately
bearing the costs of CBM represents an unexplained departure from Order
No. 888-A.
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    \42\ Citing Order No. 888-A at P 30,220.
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    77. Southern also contends that this ruling will result in an
inconsistency within the pro forma OATT, requiring incremental cost
responsibility for network customers to utilize one particular type of
external resource or off-system purchase, i.e., the utilization of CBM.
Southern argues that this conflicts with the structure of network
service under the pro forma OATT, which allows the network customer to
utilize the interfaces for both external designated network resources
and off-system opportunity purchases without additional charge.
Southern also contends that requiring network customers to pay for CBM
on the same basis as firm point-to-point service disadvantages the use
of CBM since interface capacity could only be used on an emergency
basis and therefore is not considered firm service for the purpose of
designating off-system system resources.
    78. Southern goes on to assert that the Commission's premise that
point-to-point customers are not benefiting from CBM is incorrect.
Southern notes that under normal conditions the transfer capability
reserved as CBM is made available for non-firm use by other customers.
Southern notes also that long-term point-to-point customers benefit
from the non-firm point-to-point use of that transfer capability
because associated revenues are included as revenue credits in the
numerator of the OATT rate calculations to reduce charges to long-term
firm point-to-point customers.
    79. If the Commission does not reverse its decision in Order No.
890 regarding the redesign of transmission charges, Southern seeks
clarification regarding how the CBM set-aside should be treated for
ratemaking purposes since it does not represent additional load.
Southern notes that the potential for long-term customers to receive a
rate benefit from the non-firm point-to-point use of the set-aside
raises the potential for them receiving a double credit. Southern also
suggests that the Commission defer the new rate design filing until
after NERC has adopted ATC standards under MOD-001.
    80. EEI and Idaho Power raise similar concerns, asking the
Commission to clarify that, when the transmission provider modifies its
rate design for point-to-point transmission service, it also may
propose a rate design modification to ensure that it recovers from
network and native load customers any reduction in revenues resulting
from the change in the rates for point-to-point service. Duke contends
that allocating costs of the CBM set-aside through a downward revision
to point-to-point rates would have the effect of allocating costs to
native load and network customers for a service that is not taken. EEI
and Idaho Power argue that the Commission should allow transmission
providers to modify their rates for other services in order to prevent
under-recovery of their costs of service or inappropriately shifting
costs to native load customers. EEI also requests the Commission to
clarify that the rate design change may take into consideration the
fact that transmission providers credit against the cost of service
revenues received from short-term and non-firm transmission service
provided using capacity that is set aside for CBM to ensure that long-
term firm point-to-point customers do not receive a double credit for
the use of CBM capacity.
    81. EEI requests further clarification regarding how a transmission
provider should modify unit charges that are established by settlement.
EEI argues that transmission providers should not be required to make
an entirely new cost-of-service filing and, instead, should be
permitted to reduce its rates for firm point-to-point service by the
ratio of its current transmission load and reservations without the CBM
set-aside to its transmission load and reservations plus the CBM set-
aside.
Commission Determination
    82. The Commission clarifies in response to Duke that utilities do
not need to make CBM available to LSEs on their system if the utilities
do not reserve for themselves CBM or its equivalent. Comparability only
requires transmission providers to make CBM available when they set
aside for themselves transfer capability to meet generation reliability
criteria.\43\ In order

to provide transparency and consistency regarding the use of CBM,
public utilities, working through NERC, must develop clear standards
for how CBM is determined, allocated across transmission paths, and
used.\44\
---------------------------------------------------------------------------

    \43\ We note that Duke states, in its Attachment C compliance
filing, that it has set CBM on all of its interfaces to zero because
it uses short-term line ratings (where available), which yields an
operating margin that may be used for unexpected conditions or
inaccuracies in data. See Compliance filing of Duke Energy
Carolinas, Docket No. OA07-82-000 (Sep. 10, 2007); Open Access
Transmission Tariff of Duke Energy Carolinas, LLC, FERC Electric
Tariff Fifth Rev. Vol. No. 4, Original Sheet 170H. The Commission
will address the merits of that practice in Docket No. OA07-82-000.
    \44\ Order No. 890 at P 256, 259.
---------------------------------------------------------------------------

    83. The Commission did not mandate a particular methodology for
allocating CBM over transmission paths and flowgates in Order No. 890.
We therefore reject Southern's argument that development of a
consistent methodology for calculating CBM would be harmful to LSEs
because reserve needs vary from area to area. While we expect the NERC
and NAESB process to produce a consistent and transparent process for
setting aside and allocating CBM based on LSE requests, we decline to
prescribe a specific method for how CBM should be obtained or allocated
or otherwise determine the amount of capacity that the transmission
provider has to set aside in response to requests from multiple LSEs.
    84. We disagree that a consistent CBM methodology that allows LSEs
access to historically used resources would impair reliability,
conflict with the rights of native load under FPA section 217, or
otherwise implicate varying regional and state mandates governing
adequacy issues. In any event, it is premature to consider these
questions since NERC and NAESB have yet to complete their work on the
reliability standards and business practices. We also disagree with
Southern that a consistent CBM methodology will remove the economic
benefit associated with CBM. Rather, a consistent methodology for
determining how the CBM value is determined, allocated, and used will
remove excess discretion that transmission providers previously had and
allow all LSEs to have the benefits associated with CBM.
    85. Regarding TDU Systems' request to use CBM for reserve-sharing
arrangements, we reiterate that TRM is the appropriate category for
reserve-sharing arrangements and that CBM is to meet verifiable
generation reliability criteria in times of emergency generation
deficiencies.\45\ As the Commission explained in Order No. 890, TRM may
be used for other transmission-related uncertainties as well.\46\
Because the transmission provider may set aside transfer capability for
TRM to operate the system reliably, we reject TDU Systems' request to
use CBM for reserve-sharing purposes.
---------------------------------------------------------------------------

    \45\ See id. at P 264.
    \46\ See id. at P 273.
---------------------------------------------------------------------------

    86. With regard to cost recovery of the CBM set-aside, we affirm
the decision in Order No. 890 to require transmission providers to
design their transmission charges to ensure that the class of customers
not benefiting from the CBM set-aside, i.e., point-to-point customers,
do not pay a transmission charge that includes the cost of the CBM set-
aside. Only network customers and the transmission provider on behalf
of its native load may request that transmission capacity be set aside
as CBM and, therefore, only those users of the system should bear its
costs. We disagree with Southern that, because CBM is used by network
customers, all the costs associated with CBM are already borne by
network customers through their load ratio share responsibility. As
Southern acknowledges, the rates for point-to-point service are also
calculated based on a share of total transmission system cost. If the
costs associated with CBM are not excluded from the universe of costs
allocated to all point-to-point customers, then every point-to-point
customer will end up paying a portion of those costs. The Commission's
rate design ruling is therefore consistent with, not contrary to, the
Commission's directive in Order No. 888-A for network customers and
native load to bear the cost of capacity not used by point-to-point
customers.\47\
---------------------------------------------------------------------------

    \47\See Order No. 888-A at 30,220.
---------------------------------------------------------------------------

    87. We acknowledge, as Southern claims, that point-to-point
customers do reap some indirect benefits from the CBM set-aside in that
related capacity that is not used is made available on a non-firm basis
and that, in turn, can generate revenues that are credited to the
transmission cost of service to the benefit of point-to-point
customers. We do not believe this justifies charging all point-to-point
customers for the cost of the CBM set-aside. These costs should instead
be allocated to the entities that have the exclusive right to request
the set-aside in the first instance. We agree that, in certain
circumstances, this may necessitate modification of other rate design
elements to ensure that costs are appropriately allocated and that the
transmission provider fully recovers any reduction in revenues
resulting from the change in the rates for firm point-to-point service.
Nothing in Order No. 890 precludes transmission providers from
proposing modification of rates for other services (such as network
service) as necessary to recover CBM-related costs previously paid by
point-to-point customers. Similarly, we expect that transmission
providers would address in their rate design filings any possibility
for particular customers to receive an inappropriate credit for non-
firm use of capacity set aside for CBM.
    88. We disagree that requiring transmission providers to design
their rates to properly allocate CBM-related costs conflicts with the
nature of network service or disadvantages network customers using CBM.
Under the pro forma OATT, transfer capability is made available for
network resource designations and firm point-to-point reservations on a
non-discriminatory basis. It is therefore appropriate to design rates
so that network customers and point-to-point customers pay rates based
on the service available to each.
    89. We decline to defer the filing of CBM-related rate design
proposals until completion of the NERC/NAESB standardization process.
To the extent a transmission provider's rates currently collect the
costs associated with the CBM set-aside from point-to-point customers,
those rates must be redesigned in accordance with Order No. 890. We
acknowledge, however, that the on-going NERC and NAESB standardization
processes may result in CBM being set aside and used differently in the
future. To the extent such changes implicate the allocation of costs
among those that are eligible to request or use the set-aside, the
transmission provider should file with the Commission any necessary
rate changes to ensure that CBM costs continue to be allocated
appropriately.
    90. Finally, we decline to address here what changes may be
necessary to a particular rate settlement in order to ensure that costs
associated with the CBM set-aside are allocated properly. All proposals
to allocate CBM costs will be considered on a case-by-case basis,
whether they involve rates stated in a settlement or otherwise.
(3) TRM
    91. The Commission required public utilities, working through NERC,
to complete the ongoing process of modifying TRM-related reliability
standards (MOD-008 and MOD-009). To guide NERC and NAESB in the process
of drafting TRM-related standards and business practices, the
Commission explained that transmission providers may set aside TRM for
(1) load forecast and load distribution error, (2) variations in
facility loadings, (3) uncertainty in

transmission system topology, (4) loop flow impact, (5) variations in
generation dispatch, (6) automatic sharing of reserves, and (7) other
uncertainties as identified through the NERC reliability standards
development process. To the extent capability is needed for
transmission of shared reserves, the Commission stated that it must be
included in TRM, although the Commission did not mandate the use of
reserve sharing groups.
    92. Each transmission provider was required to calculate, and
allocate on the paths and flowgates, the aggregate TRM value for all
LSEs within its area. Public utilities also were directed, working
through NERC, to establish an appropriate maximum TRM. The Commission
expressed support for NERC's plan to revise existing reliability
standards for TRM to require clear documentation of the TRM
calculation, to ensure full transparency. In addition, the Commission
required each transmission provider to make available all underlying
documentation, including work papers and load flow base cases, used to
determine TRM, to any transmission customer and LSE within its control
area, subject to a confidentiality agreement,\48\ if necessary. Because
load, facility loadings, and other uncertainties constantly deviate,
the Commission did not require that TRM set-aside capacity be sold on a
non-firm basis. The Commission explained that any request for regional
difference from the applicable TRM reliability standards must take
place through the NERC reliability standards development process.
---------------------------------------------------------------------------

    \48\ The confidentiality agreement may appropriately restrict
the sharing of sensitive information with customer personnel that
are involved only in transmission functions, as opposed to merchant
functions.
---------------------------------------------------------------------------

Requests for Rehearing and Clarification
    93. Duke asks the Commission to clarify that it intended NERC to
develop a methodology to calculate a maximum TRM number, not to put an
actual number in the reliability standard, arguing that requiring an
actual number would overstep the bounds of FPA section 215. Southern
argues that NERC must be allowed flexibility to develop appropriate TRM
methodologies so that the use of TRM will be commensurate with expected
system conditions, topography, and available capacity markets. Southern
contends that setting a maximum amount of TRM would overlook the
physical realities of the differing system configurations that
constitute the electrical system. Southern argues, in particular, that
the percentage ratings reduction proposed would be poorly suited as a
reliability margin since individual line flows can change by very large
percentages for single contingency events.
Commission Determination
    94. The Commission clarifies that NERC was not directed to identify
an actual number or a particular methodology to include in the TRM
standards, MOD-008-0 and MOD-009-0. The Commission's intent was to
require NERC and NAESB to include consistent criteria and guidelines in
the calculation and uses of TRM by transmission providers.\49\
Likewise, in response to Southern's concern regarding flexibility to
use something other than the ratings reduction method discussed in
Order No. 890, we clarify that the ratings reduction method is only an
example of a simple method that could be used.\50\ Our intent is not to
prohibit a transmission provider from using a more sophisticated
method, so long as it is consistent with the reliability standards
developed by NERC.
---------------------------------------------------------------------------

    \49\ See Order No. 890 at P 273.
    \50\ See id. at P 275.
---------------------------------------------------------------------------

e. Modeling, Assumptions and Input Data
    95. The Commission directed public utilities, working through NERC,
to modify the reliability standards MOD-010 through MOD-025 \51\ to
incorporate a requirement for the periodic review and modification of
models for (1) load flow base cases with contingency, subsystem, and
monitoring files, (2) short circuit data, and (3) transient and dynamic
stability simulation data, in order to ensure that these models are up
to date. The Commission stated that the models should be updated and
benchmarked to actual events.
---------------------------------------------------------------------------

    \51\ The MOD-010 through MOD-025 reliability standards establish
data requirements, reporting procedures, and system model
development and validation for use in the reliability analysis of
the interconnected transmission systems.
---------------------------------------------------------------------------

    96. The Commission also required transmission providers to use
consistent data and assumptions underlying operational planning for
short-term ATC and expansion planning for long-term ATC calculation, to
the maximum extent practicable. The Commission explained that such data
and assumptions include, for example, (1) load levels, (2) generation
dispatch, (3) transmission and generation facilities maintenance
schedules, (4) contingency outages, (5) topology, (6) transmission
reservations, (7) assumptions regarding transmission and generation
facilities additions and retirements, and (8) counterflows. The
Commission directed public utilities, working through NERC, to modify
ATC standards to achieve this consistency.
Requests for Rehearing and Clarification
    97. Entergy requests that the Commission acknowledge that the
benchmarking of ATC calculations to real-time ATC values is only one
piece of information to be used to evaluate ATC practices. Entergy
agrees that such updating and benchmarking can provide information
related to ATC/AFC calculations, but states that differences between
the models used to calculate ATC/AFC and actual events in fact are
going to occur. Entergy contends that the purpose of the ATC/AFC models
is not to forecast actual operating conditions, but instead to reflect
the physical transmission rights that have been previously granted and
to determine if additional physical rights may be granted.\52\ Entergy
argues that benchmarking may be helpful when evaluating ATC, but it
will not tell the whole story.
---------------------------------------------------------------------------

    \52\ Entergy asserts that actual conditions will and should
deviate from ATC/AFC models for numerous reasons. Entergy states
that transmission operators are constantly monitoring their systems
and taking actions to ensure that system constraints are mitigated
well before real-time, including modifications to transmission
outage plans, generator outage plans, and daily unit commitment
plans. Entergy contends that those actions could, for example, make
a flowgate that months ahead of time was predicted to be loaded at
100 percent to be loaded less than 50 percent in real-time. Entergy
also notes that many transmission customers only use all of their
transmission rights a small percentage of the time and, in any
event, actual operating ATC will not perfectly match posted ATC
since, for example, the level of mandatory purchases from qualifying
facility (QF) can affect real-time ATC.
---------------------------------------------------------------------------

    98. TDU Systems request that the Commission explicitly state that
assumptions regarding loop flows must be consistent for ATC calculation
and planning purposes, within the respective timeframe. TDU Systems
argue that consistency in modeling the effects of those loop flows is
necessary to ensure that neighboring transmission systems have
accurately calculated ATC not only on their own systems but also on
their interfaces with other systems. TDU Systems also ask that the
Commission clarify that the assumptions and data to be used in ATC
modeling must include the native load service obligations of LSEs as
well as the transmission provider's native load.
Commission Determination
    99. The Commission clarifies in response to Entergy that the models
used by the transmission provider to calculate ATC, and not actual ATC
values, must be benchmarked. The

Commission is concerned with the level of accuracy of the models and,
therefore, directed in Order No. 890 that the models be updated and
benchmarked to actual events. If models are not sufficiently accurate,
then ATC/AFC calculations will not generate correct results,
undermining the benefits of increased consistency and transparency of
ATC calculations. With regard to discrepancies between actual and
modeled ATC values, the Commission directed the ERO in Order No. 693 to
modify MOD-014-0 through the reliability standards development process
to require that actual system events be simulated and, if the model
output is not within the accuracy required, the model shall be modified
to achieve the necessary accuracy.
    100. We agree with TDU Systems that assumptions regarding loop
flows in calculating ATC must be consistent with those used for
planning purposes within the respective timeframes. We also agree that
loop flow impact in ATC calculation should not be restricted to the
transmission provider's control area. Loop flows that occur in the
power system must be included in the load flow models that simulate
power system conditions. Loop flows affecting ATC calculation should be
taken into account consistently by using the same models and
assumptions as used for the planning of the system. With regard to
modeling LSE uses of the system, we clarify that each transmission
provider must include the native load service obligations of LSEs as
well as the transmission provider's own load in modeling assumptions
and data used for ATC calculation.
f. ATC Calculation Frequency
    101. The Commission directed public utilities, working through NERC
and NAESB, to revise reliability standard MOD-001 to require ATC to be
recalculated by all transmission providers on a consistent time
interval and in a manner that closely reflects the actual topology of
the system, e.g., generation and transmission outages, load forecast,
interchange schedules, transmission reservations, facility ratings, and
other necessary data. The Commission stated that this process must also
consider whether ATC should be calculated more frequently for
constrained facilities.
Requests for Rehearing and Clarification
    102. Powerex asks the Commission to clarify that transmission
providers are required to update their ATC calculations when they
receive new data otherwise required to be posted under the requirements
of Order No. 890, such as updated load forecasts. Powerex argues that
the standards adopted through the NERC and NAESB processes should serve
only as minimum or ``no less frequent than'' requirements. In Powerex's
view, the specification of consistent intervals for ATC calculations
should not prohibit or deter transmission providers from calculating
and posting ATC on a more frequent basis as new data becomes available,
particularly in light of the Commission's goal in Order No. 890 to make
the ATC calculation process more transparent to customers.
    103. Southern asks the Commission to clarify that ATC, not TTC,
must be recalculated at consistent time intervals. Although the
Commission referenced ATC in Order No. 890, Southern contends that the
associated data and assumptions mentioned by the Commission (generation
and transmission outages, load forecast, interchange schedules,
transmission reservations, facility ratings, and other necessary data)
relate to TTC. Southern argues that ATC is the appropriate reference
because it can be calculated automatically with relative ease and
frequency. In comparison, Southern states that TTC requires much more
complex power flow analyses and should not be driven by changes in
parameters without expert review. Southern contends that the
calculation frequency requirements established by the Commission would
result in constantly changing values if applied to TTC, with little
time, if any, for the necessary review.
Commission Determination
    104. The Commission agrees with Powerex that the standards adopted
through the NERC and NAESB processes should serve as minimum or ``no
less frequent than'' requirements to recalculate ATC. Transmission
providers also must update their ATC calculation when they receive
substantial and material changes in data, such as updated load
forecasts, changes in topology and dispatch patterns, which may be more
frequent than the NERC and NAESB standards would otherwise require. In
the absence of substantial and material changes in data, transmission
providers are not required to update ATC on a more frequent basis than
the minimum frequency that the NERC and NAESB standards require, once
implemented. The Commission will consider the adequacy of the time
frame for ATC updates on review of these standards.
    105. In response to Southern, we reiterate that Order No. 890
directed revisions to reliability standard MOD-001 to require that ATC,
not TTC, be recalculated at consistent time intervals.\53\ However,
system topology or other changes such as transmission outages, load
forecast, interchange schedules, transmission reservations, or facility
ratings, and other necessary data that affect ATC may of course impact
one or more of the components of ATC, including TTC. While we agree
with Southern that TTC requires more involved power flow analyses, the
transmission provider should consider whether any changes in system
topology, contingency outages, or other factors are substantial enough
to merit recalculation of TTC.
---------------------------------------------------------------------------

    \53\ See Order No. 890 at P 301.
---------------------------------------------------------------------------

2. Transparency
    106. In Order No. 890, the Commission adopted a number of
requirements in order to improve the transparency of ATC calculations.
Some of these reforms applied to the pro forma OATT, including a
requirement that each transmission provider include in Attachment C to
its OATT more descriptive information concerning its ATC/AFC
calculation methodology. Other reforms applied to information posted on
OASIS, including data related to the calculation of ATC and TTC,
changes in the ATC/TTC values, disclosure of Critical Energy
Infrastructure Information (CEII), and the posting of additional ATC-
related data. Petitioners have requested rehearing and clarification of
certain of these requirements, which we address in turn.
a. OATT Transparency--Attachment C
    107. To increase transparency regarding ATC calculations, the
Commission directed each transmission provider to set forth its ATC
calculation methodology in Attachment C to its OATT. The Commission
required that each transmission provider's Attachment C must, at a
minimum: (1) Clearly identify which of the NERC-approved methodologies
it employs (e.g., contract path, network ATC, or network AFC); (2)
provide a detailed description of the specific mathematical algorithm
the transmission provider uses to calculate firm and non-firm ATC for
the scheduling horizon (same day and real-time), operating horizon (day
ahead and pre-schedule), and planning horizon (beyond the operating
horizon); (3) include a process flow diagram that describes the various
steps that it takes in performing the ATC calculation; (4) set forth a
definition of each ATC component (i.e., TTC, ETC, TRM, and CBM) and a
detailed explanation of how

each one is derived in both the operating and planning horizons; and
(5) document their processes for coordinating ATC calculations with
their neighboring systems.
    108. The Commission concluded that Attachment C must provide an
accurate documentation of processes and procedures related to the
calculation of ATC, not the actual mathematical algorithms, which
instead should be posted on their Web site with the link noted in the
Attachment C. The Commission noted that a transmission provider may
require a confidentiality agreement for CEII materials, consistent with
our CEII requirements, or may otherwise protect the confidentiality of
proprietary customer information. The Commission also required
transmission providers to file a revised Attachment C to incorporate
any changes in NERC's revised reliability standards and NAESB's
business practices related to ATC calculations, as requested by the
Commission in Order No. 890, within 60 days of completion of the NERC
and NAESB processes.
Requests for Rehearing and Clarification
    109. MidAmerican objects to the Commission's decision to require a
process flow diagram to be included in Attachment C, suggesting instead
that each transmission provider post this information on its Web site
as an alternative. MidAmerican contends that process flow diagrams
demand large amounts of computer capacity and that management of and
electronic transmittal of its OATT would become difficult if process
flow diagrams were required for other elaborate and important tasks
throughout the tariff, such as the transmission service request
procedure or the generation interconnection procedure. MidAmerican
argues that providing a web link on OASIS would achieve the
Commission's transparency objective and expeditiously provide those
that wish to navigate through a process diagram a direct access to the
document. At a minimum, MidAmerican asks that the Commission accept an
internet posting of the diagram with the web address published in
Attachment C.
    110. Southern requests clarification as to whether the Commission
intends for transmission providers to make two filings of ATC
methodologies (i.e., one when the Order No. 890 becomes effective and
another when the NERC and NAESB processes are completed) or just one
filing of such methodologies (i.e., a single filing when the NERC and
NAESB processes are completed). Southern argues that only one filing
should be required, to be made within 60 days after the NERC and NAESB
processes are completed. Southern contends that requiring a premature
filing before those processes are complete would waste transmission
providers' resources in preparing those filings and the Commission's
resources in reviewing them.
Commission Determination
    111. The Commission denies MidAmerican's request to permit a
transmission provider to post on its Web site a process flow diagram
and provide a web address in Attachment C, instead of providing the
process flow diagram as a part of the Attachment C. A link to a Web
site is not the equivalent of inclusion in the transmission provider's
OATT, leaving the Commission unable to enforce use of the process flow
diagram and the public with potentially more limited notice of any
changes to the process flow diagram. The transparency and
enforceability benefits of including the flow diagram in the tariff
outweigh any potential filing burden. Therefore, we affirm our
determination in Order No. 890 that a process flow diagram must be
filed with OATT Attachment C, and that any change of the processes or
data information identified by the process flow diagram must trigger an
update of the process flow diagram and the filing of the revised OATT,
Attachment C.
    112. In response to Southern, Order No. 890 specifically required
transmission providers to submit an intermediate filing within 180 days
after the publication of the order in the Federal Register in order to
provide transparency of the transmission provider's existing ATC
calculation methodologies. In compliance with that requirement, a
number of transmission providers, including Southern, submitted
Attachment C compliance filings on September 11, 2007. The immediate
transparency benefits of these filings will be supplemented by a
revised filing following completion of the NERC and NAESB
standardization processes. We do not believe the intermediate filing
represented an undue burden to the transmission providers, as it was no
more than a documentation of existing practices.
b. OASIS
(1) ATC/TTC Posting Requirements
    113. The Commission concluded that transmission providers must
continue to comply with existing ATC-related posting requirements, as
supplemented by Order No. 890. To that end, the Commission stated that
it would maintain a requirement for transmission providers to make
available, upon request, all data used to calculate ATC and TTC for any
constrained paths and any system planning studies or specific network
impact studies performed for customers. Transmission providers were
also directed to continue to post a list of such studies on OASIS. The
Commission required the additional posting of, at a minimum, a list of
all system impact studies, facilities studies, and studies performed
for the transmission provider's own network resources and affiliated
transmission customers, with those studies to be made available upon
request. The Commission noted that appropriate procedures to
accommodate CEII concerns should be developed to ensure eligible
entities with a legitimate interest in transmission study data can
receive access to it. The Commission required that the studies be made
available for five years, consistent with data retention requirements
pertaining to denial of service requests.
Requests for Rehearing and Clarification
    114. MidAmerican requests clarification with regard to the
interaction of the data availability obligation under Order No. 890 and
the Commission's Standards of Conduct with respect to information
requests made by affiliated transmission customers. In order to provide
comparable transmission service, MidAmerican argues that data must be
available in all circumstances. If the Commission does not clarify that
this is the case, MidAmerican requests rehearing of this provision so
that comparable information can be made available at all times.
Commission Determination
    115. The Commission clarifies that all data used to calculate ATC
and TTC for any constrained paths and any system planning studies or
specific network impact studies performed for customers are to be made
available on request, regardless of whether the customer is non-
affiliated or affiliated with the transmission provider. To the extent
the requesting party is an affiliate, the Standards of Conduct would
require that data provided to the affiliate be simultaneously posted on
the transmission provider's OASIS or Web site, as applicable.\54\
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    \54\ See 18 CFR 358.5.
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(2) ATC/TTC Narrative Explanation
    116. The Commission retained existing posting requirements for
unconstrained paths and amended its regulations relating to data posted
for

constrained paths. Specifically, the Commission required transmission
providers to post a narrative when a monthly or yearly ATC value
changes as a result of a 10 percent change in TTC on constrained paths.
Posted information must include both the (1) specific events which gave
rise to the change and (2) the new values for ATC on that path (as
opposed to all points on the network). The Commission also required the
posting of a narrative with regard to monthly or yearly ATC values when
ATC remains unchanged at a value of zero for a period of six months or
longer.
Requests for Rehearing and Clarification
    117. E.ON U.S. argues that the posting of a narrative explanation
for changes in ATC resulting from changes in TTC is unduly burdensome
and, in any event, would not provide transmission customers with any
meaningful information. E.ON U.S. contends that, using the new process
for calculating TTC, a transmission provider would have to calculate
the value for each horizon model and compare it to values in the
previous hour in order to implement the posting requirement. Where
those values change by more than 10 percent, E.ON U.S. states that the
transmission provider will have to examine individually each changed
parameter to assess its contribution to the change. E.ON U.S. contends
that, for its system, the list of parameters to be evaluated would
include generation dispatch, system configuration, loads, and net
interchanges of which there can be dozens or even hundreds per hour.
E.ON U.S. argues that this would take 24 engineers to monitor the E.ON
U.S. system alone, costing millions of dollars per year.
    118. Southern requests that the Commission clarify that the
required narratives do not need to list each and every circumstance or
occurrence that impacts TTC values from the previous month or year,
stating that such a list would likely be voluminous because of the many
conditions that affect TTC. Southern instead suggests that transmission
providers list the primary reasons for the change in TTC to the extent
they are known. Southern contends, for example, that an appropriate
reason for such changes would be a new updated monthly model, arguing
that it would not be practical to determine how much TTC may change
from each outage, service commitment or other parameter change
incorporated in an updated model.
    119. Southern also requests that the Commission clarify where the
transmission provider should post these narrative explanations and in
what form. Southern proposes that this information be posted on OASIS
via a template and data element that is to be defined by a NAESB
standard, incorporated into a revised Standards and Communications
Protocol document, and subsequently adopted by the Commission.
    120. TDU Systems argue that the Commission has set too high of a
threshold for reporting changes in ATC/TTC, arguing that the triggering
requirement should be a 10 percent decrease in ATC, rather than a 10
percent change in TTC. TDU Systems contend that TTC is a large enough
number that using a decrease of 10 percent in TTC as a trigger for
requiring a narrative explanation to be posted will result in very few
narrative explanations posted, thereby defeating the purpose of the
requirement.
    121. PJM seeks clarification of the posting requirement as applied
to transmission providers using an AFC calculation method. PJM states
that TTC is an output from, not an input to, its AFC/TTC calculations
and therefore the literal terms of the regulations do not make sense as
applied to PJM. PJM proposes to post a narrative explanation for the
reason for daily changes in ATC or TTC values as a result of changes in
AFC inputs (i.e., transmission outages, generator outages, load
forecast, and model updates) in the event the resultant ATC or TTC
value changes by 10 percent or more, requesting that the Commission
confirm that this approach would appropriately adapt the Order No. 890
posting requirement to a system such as PJM that uses an AFC
methodology. Alternatively, if the Commission does not wish to address
PJM's manner of implementation of this revised regulation in the
context of rehearing/clarification of Order No. 890, PJM asks that the
Commission allow PJM, and other similarly situated transmission
providers, to address this issue in their Order No. 890 tariff
compliance filings. In that event, PJM asks that the Commission clarify
only that such transmission providers may continue their existing
practices until the Commission acts on their compliance filings.
    122. TDU Systems also argue that the six-month trigger for posting
an explanation for zero ATC values is unsupported, asking instead that
transmission providers be required to post a narrative explanation of
zero ATC values any time those values remain at zero for a period that
affects access in a practical way, e.g., a day for daily service, two
business days for weekly service, five business days for monthly or
yearly service. TDU Systems contend that a transmission system where
ATC values remain at zero for any length of time raises serious
concerns as to the adequacy of the system and the need for significant
upgrades, and simply posting a zero value for ATC does not provide
market participants with an understanding of what is happening on the
system.
Commission Determination
    123. The Commission affirms the decision in Order No. 890 to
require transmission providers to post a brief, but specific, narrative
explanation of the reason for a change in monthly or yearly ATC values
on a constrained path as a result of a change in TTC of 10 percent or
more. As the Commission explained, this will limit the number of ATC
changes for which a narrative will be required.\55\
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    \55\ See Order No. 890 at P 369.
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    124. We believe that E.ON U.S. overestimates the burden of
complying with this requirement. Since TTC standardization is ongoing,
it is impossible to identify with precision the steps that will need to
be taken to comply with the posting requirement. The appropriate forum
to raise concerns regarding the burden of particular TTC calculation
requirements is in the NAESB standards development process. In any
event, we would expect that the posting of narratives for changes in
monthly and yearly ATC values as a result of a 10 percent change in TTC
will be triggered mainly by topology changes resulting from
transmission lines and generator in-service status, as well as new
facilities additions, that are reported on OASIS.
    125. We clarify in response to Southern that transmission providers
do not need to list each and every circumstance or occurrence that
impacts TTC values from the previous month or year and, instead, may
list the primary events that give rise to the update. Again, we expect
that TTC changes will generally result from topology changes and,
therefore, the primary reasons for an update would be changes in
schedules of transmission or generation additions, prolonged outages,
or changes in maintenance schedules causing a TTC change of 10 percent.
We agree with Southern that the transmission provider should post these
narrative explanations on OASIS via a template and data element that is
to be defined by NAESB. We direct transmission providers, working
through NAESB, to develop the OASIS functionality necessary for such
postings. Pending completion of this

work by NAESB, we direct transmission providers to post these narrative
explanations as comments on OASIS.
    126. We deny TDU Systems' request to change the triggering
requirement to a 10 percent decrease in ATC. In Order No. 890, the
Commission relaxed the ATC narrative reporting requirements proposed in
the NOPR due to concerns that the posting of those narratives would
become burdensome. We believe the Commission struck the right balance
by requiring the posting of narratives only when there is a change in
TTC of 10 percent or more and disagree that more limited postings
defeats the purpose of the posting obligation.
    127. In response to PJM, we reiterate that all transmission
providers must comply with this posting requirement. Transmission
providers using an AFC calculation method that does not base changes in
ATC on changes in TTC may comply with this requirement by posting
narrative explanations of the reasons for changes in AFC values as a
result of changes in AFC inputs that cause ATC or TTC to change by 10
percent or more. We direct each transmission provider that employs the
AFC calculation methodology to provide a statement in the compliance
filing required in section II.C describing how the narrative is derived
for ATC/TTC postings or, if such information was provided in a prior
compliance filing, a reference to that filing.
    128. We also deny TDU Systems' request to require transmission
providers to post a narrative explanation any time ATC values remain at
zero for a day for daily service, two business days for weekly service,
five business days for monthly or yearly service. The Commission
concludes that a six-month trigger for monthly or yearly ATC values
more appropriately balances the benefits of increased transparency for
the Commission and customers against the burden on transmission
providers to make such postings. If the frequency of these postings
proves inadequate, the Commission can revisit this requirement in a
future order.
(3) CEII
    129. The Commission acknowledged in Order No. 890 that certain data
and studies required to be made public may contain CEII and that the
Commission has a responsibility to protect that information. In order
to provide transparency and avoid undue delays in providing information
to those with a legitimate need for it, the Commission required that
transmission providers establish a standard disclosure procedure for
CEII required to be disclosed in Order No. 890. The Commission stated
that transmission providers will be responsible for identifying CEII
and facilitating access to it for appropriate entities and the
Commission will be available to resolve disputes if they arise.
    130. With regard to procedures to access CEII, the Commission noted
that transmission customers already have digital certificates or
passwords to access publicly restricted transmission information on
OASIS. The Commission suggested that transmission providers could set
up an additional login requirement for users to view CEII sections of
the OASIS, requiring users to acknowledge that they will be viewing
CEII and to sign a nondisclosure agreement at the time the customer
obtains access to that portion of the OASIS. The Commission explained
that only information that meets the criteria for CEII, as defined in
section 388.113 of the Commission's regulations,\56\ should be posted
in this section of the OASIS.
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    \56\ 18 CFR 388.113.
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Requests for Rehearing and Clarification
    131. E.ON U.S. contends that the Commission should not allow
posting of CEII on OASIS, arguing that information is designated as
CEII because it relates to the integral operations of the nation-wide
power grid and that, with access to this information, a terrorist or
other bad actor could inflict real, substantial harm on the power grid.
E.ON U.S. states that posting CEII on a transmission provider's OASIS,
a Web site that is openly connected to the internet, will impair the
transmission provider's ability to adequately protect this information,
even with password protection. E.ON U.S. suggests there are other ways
of providing transmission customers with such CEII, such as individual
meetings upon request.
    132. New York Transmission Owners request that transmission
providers be authorized to determine, on a case-by-case basis, the
specific level and amount of CEII that a requesting customer may
obtain. New York Transmission Owners argue that a terrorist seeking to
harm our country's energy infrastructure will not likely be concerned
with having to sign a confidentiality agreement or obtain multiple
passwords.
Commission Determination
    133. We agree with E.ON U.S. that posting CEII on OASIS may not
provide adequate protection of CEII and that transmission providers may
therefore develop other standard disclosure procedures to provide
relevant CEII to transmission customers on a timely basis. The
Commission did not require CEII postings on OASIS in Order No. 890 and,
instead, discussed use of OASIS as one potential disclosure
mechanism.\57\ The Commission required transmission providers to
establish a standard procedure for disclosing relevant CEII on a timely
basis, but did not specify a particular disclosure mechanism.
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    \57\ See Order No. 890 at P 404.
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    134. Similarly, transmission providers may determine on a case-by-
case basis the specific level of CEII a customer may obtain, provided
that the information is made available to appropriate recipients on a
timely basis. If a transmission provider chooses to post CEII on a
protected section of its OASIS, the transmission provider can and
should verify the identity of transmission customers who access that
information as it would for any confidential information.
(4) Additional Data Posting
    135. The Commission also required transmission providers to post on
OASIS metrics related to the provision of transmission service under
the OATT. Specifically, non-ISO/RTO transmission providers were
directed to post (1) the number of affiliate versus non-affiliate
requests for transmission service that have been rejected and (2) the
number of affiliate versus non-affiliate requests for transmission
service that have been made. This posting must detail the length of
service request (e.g., short-term or long-term) and the type of service
requested (e.g., firm point-to-point, non-firm point-to-point or
network service). The Commission stated that the affiliate posting
requirements do not apply to ISOs and RTOs since they do not have any
affiliates.
    136. The Commission also required transmission providers to post
their underlying load forecast assumptions for all ATC calculations and
to post, on a daily basis, their actual daily peak load for the prior
day and load forecasts and actual daily peak load for both system-wide
load (including native load) and native load. ISOs and RTOs are
required to post this load data for the entire ISO/RTO footprint and
for each LSE or control area footprint within the ISO/RTO.
Requests for Rehearing and Clarification
    137. E.ON LSE requests clarification whether the requirement in
section 37.6(e)(2) of the Commission's regulations to post information
regarding denials of service applies to denials of requests. Washington
IOUs

request clarification on the requirement to post information regarding
transmission service requests from affiliates, stating that it is not
clear what the Commission means by ``requests for transmission
service.'' They suggest that the reference could be to requests for