[Federal Register: January 16, 2008 (Volume 73, Number 11)]
[Rules and Regulations]
[Page 2983-3143]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[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, (202) 502-6540.
Daniel Hedberg (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426, (202) 502-6243.
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.
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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
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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
[[Page 2987]]
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
[[Page 2988]]
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.
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\23\ Citing American Transmission Co. LLC, 95 FERC ] 61,387
(2001).
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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.
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\24\ April 11 Order at P 20.
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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.
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\25\ Id. at P 22.
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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.
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\26\ See Order No. 890 at P 135, n.105.
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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.
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\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).
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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
[[Page 2989]]
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.
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\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
[[Page 2990]]
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).
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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.
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\33\ See Order No. 890 at P 310.
\34\ See id. at P 301.
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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
[[Page 2991]]
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\
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\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).
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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.
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\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).
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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.
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\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
[[Page 2992]]
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
[[Page 2993]]
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
[[Page 2994]]
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\
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\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.
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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.
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\45\ See id. at P 264.
\46\ See id. at P 273.
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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\
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\47\See Order No. 888-A at 30,220.
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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
[[Page 2995]]
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.
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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.
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\49\ See Order No. 890 at P 273.
\50\ See id. at P 275.
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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.
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\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.
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\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.
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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
[[Page 2996]]
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.
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\53\ See Order No. 890 at P 301.
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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
[[Page 2997]]
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
[[Page 2998]]
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
[[Page 2999]]
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
[[Page 3000]]
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
transmission service by affiliated merchant or trading entities or
requests for transmission service by the transmission provider's
merchant function, including requests to designate or undesignate
network resources and requests to procure secondary network service to
serve native load.
138. TDU Systems request that the Commission reconsider its
decision to exempt RTOs and ISOs from the requirement to post data
regarding their processing of transmission service requests. Although
RTOs and ISOs have no generation affiliates, TDU Systems argue that
requiring RTOs and ISOs to post information as to the number of
requests made and rejected would make the acquisition of transmission
services more transparent, serve as a signal for potential congestion
problems on the system that should be studied through the planning
process, and alert market participants to the emergence of market power
in local submarkets.
139. Constellation requests that the Commission clarify that the
requirement to post underlying load forecast assumptions includes a
complete list of modeling assumptions, protocols and automation
modifications, including what the adjustments are and how they are
applied. Constellation states that it requested that such information
be required in its NOPR comments, but that it is unclear whether the
requirement in Order No. 890 is broad enough to reflect that request.
140. E.ON LSE requests that the Commission grant rehearing to
permit utilities to decline to publicly post information regarding
actual load and forecasts where such information is commercially
sensitive or where customer-specific information is deemed confidential
by the affected customer. E.ON LSE requests that such commercially
sensitive information instead be posted four weeks after the time
period that the data covers. E.ON LSE contends that disclosure of
customer-specific load forecasts could have adverse competitive
effects, such as a daily forecast signaling to sellers that a utility
is in substantial need for additional energy during the upcoming day's
operations. E.ON LSE contends that the goal of transparency is
sufficiently met even with a slight delay in posting commercially
sensitive forecasts and load data.
Commission Determination
141. In Order No. 890, the Commission required transmission
providers to post on OASIS metrics regarding transmission service
requests. The Commission did not distinguish between types of requests
for transmission service. Transmission providers therefore should
include in their metrics any type of request for service, including
transmission service requests by affiliated merchant or trading
entities as well as requests by the transmission provider's merchant
function to designate or undesignate network resources or to procure
secondary network service to serve native load. We revise our
regulations to make this clear.
142. In response to TDU Systems, we clarify that Order No. 890 did
not exempt RTOs and ISOs from the requirement to post metrics related
to the provision of transmission service. While the affiliate posting
requirements do not apply to RTOs and ISOs,\58\ the requirement to post
metrics regarding all transmission service requests remains.\59\ We
agree with TDU Systems that requiring RTOs and ISOs to post non-
affiliate transmission service request metrics improves the
transparency of transmission service request processing by those
transmission providers.
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\58\ See Order No. 890 at P 414.
\59\ See 18 CFR 37.6(i)(1) and (2).
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143. In response to Constellation, we clarify that underlying load
forecast assumptions should include economic and weather-related
assumptions. We revise our regulations to clearly state the obligation
to post both actual daily peak load and load forecast data, as required
in Order No. 890.\60\ We decline to adopt E.ON LSE's request to delay
release of load data required to be posted in Order No. 890. Posting
load forecast and actual load data on a control area and LSE level
provides necessary transparency to transmission customers and does not,
in our view, raise serious competitive implications.\61\ If there is
customer-specific information deemed confidential by the affected
customer that impedes the ability of the transmission provider to post
this data, we will consider requests for exemption from the posting
requirement on a case-by-case base.
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\60\ See Order No. 890 at P 416.
\61\ See id. at P 417.
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(5) Requests for Additional Transparency
Requests for Rehearing and Clarification
144. Constellation repeats a request from its NOPR comments to
require transmission providers to post certain additional modeling
data, modeling support information, and model benchmarking and
forecasting data/TSR study audit data (identified in an attachment to
its request for rehearing). Constellation argues that, since Order No.
890 requires transmission providers to calculate much of this
additional information, the Commission should require that it be posted
as well. Constellation contends that these postings would allow
transmission customers and the Commission to assess the likely
availability of transmission capacity, verify or challenge the
conclusions reached by the transmission provider on a specific
transmission request, and identify constraints and congestion, as well
as physical or financial measures that could be taken to optimize the
use of transmission system.
145. EPSA asks the Commission to clarify that the standards
developed during the NAESB process should require transmission
providers to post essential details of ETCs that affect current
customers' access to transmission capacity, including duration and
volume, priority rights, redispatch and scheduling rights, and any
other rights that affect others' use of the grid. As part of these
postings, EPSA suggests that transmission providers be required to
include information concerning transmission arrangements that are not
provided under the OATT, e.g., pre-OATT transmission arrangements. EPSA
argues that non-OATT transmission arrangements often include terms that
are inconsistent with OATT terms and which can impact OATT customers'
access to the grid. Unless transmission providers are required to post
ETC-related information, EPSA contends that there will be no way for
market participants to determine whether the transmission provider has
appropriately modeled ETC set-asides.
146. Powerex makes a similar request, reiterating a NOPR proposal
that the Commission require transmission providers to post those
provisions of pre-Order No. 888 contracts that affect current
customers' access to transmission capacity, including duration and
volume, priority rights, redispatch and scheduling rights, and any
other rights that affect transmission access. Powerex further requests
that the Commission prohibit the continuation
[[Page 3001]]
of grandfathered contracts unless the parties can point to a provision
within the existing contract that contains explicit and guaranteed
rights to extend or renew the contract term and reaffirm that pre-Order
No. 888 contracts cannot be altered upon their expiration. Powerex
complains that the Commission did not address these proposals in Order
No. 890 and that no commenting party put forward credible evidence to
rebut the information Powerex presented the Commission in its NOPR
comments.
147. TDU Systems argue that transmission providers should be
required to provide customers with access to modeling software used to
calculate ATC values. TDU Systems state that Commission staff expressed
concern at the Technical Conference held on October 12, 2006, in this
docket that customers could find it difficult to sort through and use
the large volume of data the Commission proposed to be posted by the
transmission provider. TDU Systems argue that providing access to the
modeling software used by the transmission provider to calculate ATC
would resolve many of these concerns and better enable transmission
customers to replicate and verify transmission provider ATC
calculations, avoiding the potential for protracted litigation over the
ATC results. TDU Systems contend that any proprietary or licensing
concerns of the transmission provider or its vendors could be addressed
through reasonable charges for use of the software and/or appropriate
confidentiality agreements.
Commission Determination
148. In Order No. 890, the Commission required transmission
providers to make available, upon request, all data used to calculate
ATC, TTC, CBM and TRM for any constrained posted path.\62\ We believe
that this adequately addresses Constellation's request for access to
modeling data used by the transmission provider. Specifically, we
expect transmission providers to make available, upon request and
subject to appropriate confidentiality protections and CEII
requirements, the following modeling data: (1) Load flow base cases and
generation dispatch methodology; (2) contingency, subsystem,
monitoring, change files and accompanying auxiliary files; (3)
transient and dynamic stability simulation data and reports on
flowgates which are not thermally limited; (4) list of transactions
used to update the base case for transmission service request study;
(5) special protection systems and operating guides, and specific
description as to how they are modeled; (6) model configuration
settings; (7) dates and capacities of new and retiring generation; (8)
new and retired generation included in the model for future years; (9)
production cost models (including assumptions, settings, study results,
input data, etc.), subject to reasonable and applicable generator
confidentiality limitations; (10) searchable transmission maps,
including PowerWorld or PSSE diagrams; (11) OASIS names to Common Names
table and PTI bus numbers; and, (12) flowgate and interface limits
including limit category (thermal, steady state or transient, voltage
or angular). We decline, however, to require the transmission provider
to post this information on OASIS, as Constellation suggests. We
conclude that making this information available on request provides
sufficient transparency for customers without unduly burdening the
transmission provider.
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\62\ See id. at P 348.
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149. With regard to the modeling support information sought by
Constellation, we believe much of this information should already be
stated in each transmission provider's Attachment C. In Order No. 890,
the Commission required each transmission provider to set forth in the
Attachment C to its OATT the ATC calculation methodology used by the
transmission provider.\63\ To the extent necessary, we clarify that the
step-by-step modeling study methodology and criteria for adding or
eliminating flowgates (permanent and temporary) is part of the ATC
methodology that must be stated in the transmission provider's
Attachment C. We direct any transmission provider that has failed to
include this information in its Attachment C to include that
information as part of the compliance filing directed in section II.C.
If the transmission provider has already satisfied this obligation in a
previous compliance filing, it should refer to that filing instead.
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\63\ See id. at P 323.
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150. We deny as premature Constellation's request to require OASIS
postings of additional model benchmarking and forecasting data/TSR
study audit data. Such information would be utilized in the process of
updating and benchmarking models to actual events, which is the subject
of ongoing efforts to modify relevant reliability standards from the
MOD and facilities design, connections and maintenance (FAC) groups.
151. We decline to impose additional posting requirements regarding
ETC uses, as requested by EPSA and Powerex. In Order No. 890, the
Commission required transmission providers to make available all data
used to calculate ATC for constrained paths and any system planning
studies or specific network impact studies performed for customers.\64\
This would include information regarding ETC uses, including
grandfathered agreements, that affect ATC calculations or study
results. EPSA and Powerex fail to demonstrate that it is necessary to
require the posting of additional information regarding ETC uses to
verify the accuracy of the transmission provider's ATC calculations. We
note in response to Powerex that, if any new service taken upon
expiration of a pre-Order No. 888 contract, the terms and conditions of
the transmission provider's OATT would apply.\65\
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\64\ See id. at P 348.
\65\ See Order No. 888 at 31,655.
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152. We deny TDU Systems' request to require transmission providers
to grant customers access to proprietary modeling software used to
calculate ATC values. The Commission believes at this time that the
requirements of Order No. 890 are sufficient to achieve the
Commission's transparency goals without further requiring the
disclosure of proprietary software.
B. Coordinated, Open, and Transparent Planning
1. The Need for Reform
153. In Order No. 890, the Commission required transmission
providers to participate in a coordinated, open, and transparent
planning process on both a local and regional level. Transmission
providers, including RTOs and ISOs, were directed to submit a
compliance filing describing their proposals for a coordinated and
regional planning process that comply with the planning principles and
other requirements of Order No. 890. The transmission planning process
must be documented as an attachment to the transmission provider's
OATT.
154. The Commission determined that planning-related reforms were
necessary in order to limit opportunities for undue discrimination and
to ensure that comparable transmission service is provided by all
public utility transmission providers. The Commission stated that it
did not intend to reopen prior approvals regarding planning processes
adopted by RTOs and ISOs and, instead, sought to ensure that such
planning processes are
[[Page 3002]]
consistent with or superior to the requirements of Order No. 890. In
order for an RTO's or ISO's planning process to be open and
transparent, transmission customers and stakeholders must be able to
participate in each underlying transmission owner's planning process.
The Commission therefore directed RTOs and ISOs to indicate in their
compliance filings how participating transmission owners within their
footprint will comply with the planning requirements of Order No. 890.
155. The Commission also noted that the planning obligations
imposed in Order No. 890 did not address or dictate which investments
identified in a transmission plan should be undertaken by transmission
providers. Through the principles adopted by the Commission, a process
was established through which transmission providers will coordinate
with customers, neighboring transmission providers, affected state
commissions, and other stakeholders in order to ensure that
transmission plans are not developed in an unduly discriminatory
manner.
Requests for Rehearing and Clarification
156. E.ON U.S challenges the Commission's authority to adopt
transmission planning rules beyond the implementation of service
reservations or requests by customers. E.ON U.S. argues that the
Commission's reliance on new section 217(b)(4) of the FPA is misplaced
because that provision does not enlarge the Commission's authority and,
in any event, Order No. 890 goes beyond assuring that LSEs have
adequate transmission service. E.ON U.S. contends that characterizing
transmission planning as a practice affecting rates would require an
expansion of the Commission's jurisdiction over the underlying rate,
which it argues does not exist.
157. Southern states that it supports the bulk of the coordinated
planning provisions of Order No. 890, but nonetheless argues that
reform is not needed to ensure that transmission planning is performed
on a non-discriminatory basis. Southern states that it has invested
billions of dollars in transmission over the last decade and expects to
continue the trend of considerable investment through the foreseeable
future. Southern also contends that it and other vertically-integrated
utilities have obligations to procure generation through
nondiscriminatory requests for proposals and that contracts awarded to
any non-affiliated generator are already incorporated into the planning
process as designated resources. Southern therefore contends that it
does not have a disincentive to impede the ability of lower cost
generation to access its control area. Southern suggests that any
failure to upgrade interfaces is due to the lack of long-term firm
service commitments to justify the upgrade, not a desire to keep lower-
cost power from accessing the transmission provider's control area.
158. NYISO challenges the Commission's reform of previously-
approved RTO and ISO planning processes, arguing that the Commission
cannot require changes to the NYISO planning process without first
making a finding that it is no longer just and reasonable. NYISO
contends that no such finding was made in Order No. 890, nor did the
Commission identify discrimination in areas with centralized markets,
such as NYISO.
159. NRECA, Old Dominion, and TDU Systems ask the Commission to
clarify that those RTOs and ISOs and other public utility transmission
providers able to demonstrate that their planning processes are
consistent with or superior to the requirements of Order No. 890 must
nevertheless still file their planning process as part of their OATTs.
These petitioners contend that requiring an RTO or an ISO to include
the details of its planning process in its OATT, rather than its
operating agreements, business manuals or Web site postings, will
enable the Commission to monitor compliance with the reformed planning
principles of Order No. 890 and provide needed transparency for
customers. Entergy requests clarification that a transmission provider
that has transferred authority over planning activities to an
independent transmission coordinator may make the same compliance
filings as an RTO/ISO, demonstrating that its existing planning process
is consistent with or superior to the Order No. 890 requirements.
160. Old Dominion asks the Commission to clarify that the list of
requirements in paragraph 602 of Order No. 890 (regarding the level of
detail to be included in the OATT) is not exclusive and that, instead,
every transmission provider must include the entirety of its planning
process in its Attachment K with sufficient detail for stakeholders to
understand that process. TDU Systems seek further clarification that
transmission providers that have not turned over operational control of
their facilities to an RTO or ISO must comply with the Attachment K
filing obligations even if their facilities are governed by non-OATT
arrangements, such as facilities agreements.
161. Several petitioners ask the Commission to clarify whether
individual transmission-owning members within an RTO/ISO must comply
with the planning-related posting and filing requirements of Order No.
890.\66\ New York Transmission Owners argue that, where there is an
existing compliant regional planning process conducted by an RTO or
ISO, participation in the planning process by a transmission owner is
sufficient to satisfy the requirements of Order No. 890. Old Dominion
and TDU Systems, however, seek confirmation that each of the nine
planning principles adopted by the Commission apply equally to
transmission owners that are members of an RTO, otherwise the RTO's
planning process will be insufficient to satisfy the requirements of
Order No. 890. TDU Systems argue that RTO and ISO tariff filings must
provide detail on how the RTO will ensure transmission owner compliance
with planning requirements and that reliance on statements of
commitment to comply would be insufficient. Old Dominion contends that
all filing and posting obligations should rest with the RTO or ISO and
not their transmission-owning members. EEI suggests that the processes
for incorporating the planning processes of transmission owning members
of RTOs and ISOs should be addressed by each RTO and ISO.
---------------------------------------------------------------------------
\66\ See, e.g., EEI, National Grid, New York Transmission
Owners, Old Dominion, and TDU Systems.
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162. National Grid objects to any obligation to allow stakeholders
an opportunity to preview the internal planning deliberations of
transmission-owning RTO/ISO members prior to presentation of plans to
the RTO or ISO. National Grid argues that this would give special
interest stakeholders two opportunities to oppose specific projects,
once at the local level without the full participation of the region
and again at the regional level, and undermine the ability of the
regional process to resolve conflicts between competing proposals.
National Grid contends that it would be unfair to require transmission
owners to open up their internal deliberations in advance of the
regional planning process while allowing other stakeholders to
deliberate in private their own strategies for the regional planning
process. National Grid asks the Commission to clarify that the regional
planning process is the appropriate forum in which stakeholders can
examine each other's upgrade proposals. National Grid argues that the
adoption of separate local planning processes is not necessary to
remedy undue discrimination and is unnecessary given
[[Page 3003]]
that stakeholders in the ISO-NE regional planning process have an
opportunity to comment on all aspects of the transmission plan, even
those developed by the underlying transmission owners.
163. Several petitioners challenge the Commission's decision in
Order No. 890 not to mandate the construction of facilities identified
in a transmission plan. TAPS argues that the Commission's finding that
discrimination exists in expansion decisions compels obligating
transmission providers to build needed facilities to accommodate uses
identified in the planning process or explain why they cannot do so.
TAPS contends that, under Order No. 890, a transmission provider can
choose to build only the planned upgrades that benefit its native load,
leaving a weak and uneven grid that prevents embedded TDUs from
accessing economic alternatives.
164. TAPS asks that the following measures be adopted to protect
the interest of customers potentially harmed by failing to obligate the
transmission provider to construct facilities identified in the
transmission plan. First, TAPS suggests that transmission providers be
required to accept any request for transmission to a network customer
load, if necessary by redispatch shared on a load-ratio basis, if the
request would have been accepted if the transmission provider's own
load had been designated the sink. Second, TAPS asks the Commission to
require transmission providers to accept a network customer's timely
designated network resource so long as the designation is consistent
with the regional transmission plan and the long-term projections and
planning information provided by the customer pursuant to OATT Sec.
31.6 and in the planning process, supporting the network resource
designation through redispatch if necessary, with costs shared on a
load-ratio basis. Third, TAPS suggests that transmission providers be
required to offer embedded cost sales to transmission-dependent
utilities if the provider's failure to plan and construct on a
comparable basis has left those embedded utilities trapped without
reasonable access to competitive alternatives. Finally, TAPS asks the
Commission to make clear that its ``toolbox'' to address egregious
failures to plan and construct a robust grid that meets the needs of
network customers includes the exercise of jurisdiction over the
transmission component of bundled retail sales of a particular utility
to remedy undue discrimination.\67\
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\67\ Citing New York v. FERC, 535 U.S. 1 (2002).
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165. TAPS argues that these measures would provide transmission
providers with the right financial incentives to construct facilities
identified in the transmission plan. If the transmission provider fails
to build and there is insufficient capacity to accommodate planned
uses, TAPS argues it is appropriate for the transmission provider to
share the cost of providing alternative service. TAPS argues that this
would also mitigate the Commission's concern that imposing an
obligation to build would conflict with the need for transmission plans
to change over time.
166. TAPS also suggests that the Commission monitor the
transmission provider's actions by requiring any denial of service to a
network customer be reported to the Commission so that the transmission
provider can demonstrate to enforcement staff that the transmission
provider has adequately planned for its customers and made diligent
efforts to build planned upgrades. TAPS also argues that transmission
providers should be required to demonstrate that they are making good
faith efforts to obtain any necessary state and local siting approvals
and to acquire any property rights necessary to construct planned
facilities in order to show that they are not selecting projects for
construction that favor their own uses over the uses of their network
customers.
167. TDU Systems agree that better planning will not remedy or
mitigate undue discrimination without an enforceable obligation to
actually construct upgrades needed to ensure reliable and economic
service to LSEs. TDU Systems argue that an obligation to build would be
consistent with other reforms adopted in Order No. 890, such as
extending the minimum term of contracts eligible for rollover rights
and eliminating the price cap on reassignments of capacity, by ensuring
that adequate capacity exists to accommodate transmission service
requests. They contend that the failure to mandate expansion of the
grid is particularly egregious in situations when zero ATC values are
posted on a recurring or lengthy basis, which they argue should trigger
a rebuttable presumption that congestion exists on the transmission
system and that upgrades are needed. TDU Systems contend that failing
to require transmission providers to expand their systems in these and
other situations is inconsistent with the requirement of section
217(b)(4) of the FPA for the Commission to exercise its authority to
facilitate the planning and expansion of transmission facilities to
meet the reasonable needs of LSEs.
168. TDU Systems suggest that the Commission strengthen and
aggressively enforce the existing construction obligations in the pro
forma OATT and subject transmission providers that fail to implement a
transmission plan in good faith to sanctions. TDU Systems argue that
section 28.2 of the pro forma OATT should be amended to require a
transmission provider to do more than endeavor to construct new
facilities needed to meet network customer load or, in the alternative,
the Commission should indicate that it will aggressively enforce the
existing obligation to build. They request that the Commission adopt a
clear policy of sanctions for cases in which a transmission provider is
found to have failed to proceed in good faith and with due diligence in
implementing the planning process. TDU Systems ask the Commission to
clarify in particular that it will consider revocation of market-based
rate authority for bad faith in implementing the transmission planning
and expansion requirements under Order No. 890.
169. NRECA also urges the Commission to reiterate and enforce the
existing obligations to build in order to meet its service obligations
to network and long-term point-to-point customers under the pro forma
OATT.\68\ NRECA argues that the obligation to expand capacity should be
viewed as part and parcel of the transmission provider's obligation to
plan for these customers and that statements to the contrary in Order
No. 890 should be clarified. NRECA argues that leaving the transmission
provider with the discretion not to build facilities identified in the
transmission plan would allow it to discriminate in favor of its native
load customers to the detriment of network and long-term point-to-point
customers.
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\68\ Citing pro forma OATT sections 13.5, 15.4 and 28.2.
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170. Washington IOUs request clarification that the planning
requirements of Order No. 890 do not supersede the planning and
coordination activities undertaken by a transmission provider under its
network operating agreements. Washington IOUs state that transmission
providers providing network service currently engage in local planning
and coordination activities with network customers to ensure their
needs are met and that such activities should not be
[[Page 3004]]
superseded by the planning-related reforms of Order No. 890.
Commission Determination
171. The Commission affirms the decision in Order No. 890 to amend
the pro forma OATT to require coordinated, open and transparent
transmission planning on both a local and regional level. Although the
Commission encouraged utilities to engage in joint planning in Order
No. 888-A, it placed no affirmative obligation on transmission
providers to coordinate with their customers in transmission planning
or otherwise publish the criteria, assumptions, or data underlying
their transmission plans, nor were transmission providers required to
coordinate planning activities with other transmission providers in
their region. This lack of clear criteria regarding planning
obligations has created opportunities for undue discrimination by
transmission monopolists with an incentive to deny transmission or
offer transmission on an inferior basis.
172. Petitioners generally do not challenge the Commission's
conclusion that the lack of coordination, openness, and transparency
results in opportunities for undue discrimination in transmission
planning and, instead, raise more narrow arguments regarding particular
aspects of the planning reforms. E.ON U.S. argues that the Commission
must limit the scope of the planning requirements to implementation of
service requests. We disagree. The Commission has a statutory
obligation under sections 205 and 206 of the FPA to ensure that each
public utility's rates, charges, classifications, and services are just
and reasonable and not unduly discriminatory. The Commission has
exercised jurisdiction over planning-related proposals submitted by
individual transmission providers in the past, rejecting arguments
regarding a lack of jurisdiction.\69\ Transmission planning activities
are within our jurisdiction and, therefore, we have a duty under FPA
section 206 to remedy undue discrimination in this area and a further
obligation under FPA section 217 to act in a way that facilitates the
planning and expansion of facilities to meet the reasonable needs of
LSEs.
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\69\ See New York Independent System Operator, Inc., 109 FERC ]
61,372 at P 18 (2004); Southwest Power Pool, Inc., 109 FERC ] 61,010
at P 78 (2004).
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173. The fact that transmission providers, such as Southern, have
undertaken some transmission investment in recent years does not mean
that planning reform is not needed. Southern does not challenge the
fundamental conclusion that it is in the economic self-interest of
transmission monopolists to discriminate in the provision of service
and, in turn, in planning-related activities. The ability of generators
to participate in requests for proposals for generation service does
not adequately respond to the need for a coordinated, open, and
transparent transmission planning process that considers the needs of
all customers as well as the transmission provider itself. The planning
process adopted in Order No. 890 is designed to enhance the ability of
all customers to make long-term firm service commitments by allowing
them to participate in the transmission provider's planning activities.
174. The Commission also based its planning-related reforms on the
need to ensure comparable transmission service by all transmission
providers, including RTOs and ISOs. We therefore disagree with NYISO
that the Commission failed to justify application of the Attachment K
filing obligations to RTOs and ISOs. The Commission was not required to
find each and every tariff unjust and unreasonable to adopt this
rulemaking, and, instead, had the discretion to adopt principles of
generic applicability to govern all transmission tariffs. Indeed, we
made clear, and reiterate here, that RTOs and ISOs can continue to rely
on their existing planning processes if those processes meet the
requirements of Order No. 890. As the Commission explained, it is not
our intention to reopen prior approvals simply for the sake of doing
so, but rather to ensure that those previously approved planning
processes fulfill the obligations imposed on all transmission providers
in Order No. 890.\70\
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\70\ See Order No. 890 at P 437.
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175. We therefore affirm the decision to require all transmission
providers to comply with the planning-related reforms adopted in Order
No. 890, including RTOs and ISOs. We agree with Old Dominion that the
filing and posting requirements stated in Order No. 890 apply only to
the transmission provider, e.g., the RTO or ISO, and not the
transmission-owning RTO/ISO members without an OATT.\71\ Each RTO and
ISO may fulfill its obligations under Order No. 890 by delegating
certain actions to, or otherwise relying on, their transmission-owning
members, provided that the rights and responsibilities of all parties
are clearly stated in the transmission provider's OATT. In the end,
however, it is each RTO's and ISO's responsibility to demonstrate
compliance with each of the nine planning principles adopted in Order
No. 890 since it is the entity with the Attachment K on file.
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\71\ As the Commission noted in Order No. 890, transmission
owning members of an RTO or ISO that continue to have OATTs on file
under which they provide service over jurisdictional facilities not
under control of the RTO or ISO would continue to have filing
obligations under Order No. 890, like any other transmission
provider. See id. at P 440, n.247. This would apply equally to a
transmission provider that has retained operational control of
facilities governed by other non-OATT arrangements.
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176. We clarify in response to National Grid that an RTO or ISO
would not be able to satisfy the requirements of Order No. 890 if the
plans developed by its transmission-owning members and relied upon by
the RTO/ISO did not also satisfy those requirements. A fundamental
assumption underlying National Grid's argument is that issues addressed
in a local planning proposal should be final prior to its introduction
at the regional level. Yet such finality could exclude customers from
the development of aspects of what eventually becomes the regional plan
implemented by the RTO or ISO. As the Commission explained in Order No.
890, local planning issues may be critically important to some
transmission customers, such as those embedded within the service areas
of individual transmission owners.\72\ While we leave the mechanics of
incorporating the planning processes of transmission owning members to
each RTO and ISO, as EEI suggests, it would not be appropriate to
entirely exclude such processes as proposed by National Grid.
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\72\ See id. at P 440.
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177. To the extent necessary, we clarify in response to NRECA, Old
Dominion and TDU Systems that every transmission provider, including
RTOs and ISOs, must submit a compliance filing stating its transmission
planning process in an attachment to its OATT. This tariff language
must satisfy all of the requirements of Order No. 890 with sufficient
detail for stakeholders to understand the planning process implemented
by the transmission provider. To the extent the transmission provider
previously received Commission approval to delegate planning
responsibilities to an independent transmission coordinator, the
transmission provider may demonstrate in its compliance filing that its
planning process is consistent with or superior to the Order No. 890
planning requirements, similar to the RTO and ISO compliance filings.
178. The Commission declines to expand the pro forma OATT to place
additional obligations on the
[[Page 3005]]
transmission provider to construct facilities identified in its
transmission plan. As the Commission explained in Order No. 890, there
may be reasons a transmission provider declines to undertake a
particular project given the complexity of the transmission grid and
changing conditions of supply and demand.\73\ Our focus is therefore on
the process leading to the transmission plan and not the construction
of specific facilities. This does not, as some petitioners argue,
undermine the construction-related obligations that exist under
sections 13.5, 15.4 and 28.2 of the pro forma OATT. The planning-
related reforms adopted in Order No. 890 are intended to support, not
replace, those requirements by establishing a process to govern all
planning-related decisions.
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\73\ See id. at P 594.
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179. We therefore believe adequate protections are in place to
ensure that transmission providers do not unduly discriminate in the
selection of which facilities they choose to construct to the detriment
of their customers. If a particular customer believes that its
transmission provider has in fact not complied with its OATT
obligations, the customer should bring the matter to the Commission's
attention, such as by filing a complaint. Indeed, the planning-related
reforms adopted in Order No. 890 will facilitate tariff compliance by
opening up the transmission provider's decisional process, providing
much needed transparency in the area of transmission planning.
180. We deny as unnecessary TAPS' request to impose additional
accountability mechanisms or require other demonstrations regarding a
transmission provider's construction decisions or to generically
address the appropriateness of sanctions, including revocation of
market-based rate authority, for non-compliance with tariff
obligations. We will likewise deny requests to revise the construction-
related obligations of the pro forma OATT. The Commission will remain
actively involved in the review and implementation of the transmission
planning processes required in Order No. 890, during and beyond the
initial compliance phase, to ensure that the potential for undue
discrimination in planning activities is adequately addressed. Further,
we expect transmission customers to advise the Commission if
transmission providers do not adhere to the terms of the tariff
provisions we ultimately approve. In the absence of specific evidence
that a transmission provider has failed to satisfy its tariff
obligations, either under sections 13.5, 15.4 or 28.2 of the pro forma
OATT or its Attachment K planning process, we believe it unnecessary to
adopt the additional measures proposed by TAPS. In the case of tariff
non-compliance, the Commission will consider these and any other
remedies that may be appropriate on a case-by-case basis in the context
of the specific facts presented.
2. Planning Principles
181. The Commission identified nine planning principles in Order
No. 890 that must be satisfied for a transmission provider's planning
process to be considered compliant with that order. These nine planning
principles are:
(1) Coordination--the process for consulting with transmission
customers and neighboring transmission providers;
(2) Openness--planning meetings must be open to all affected
parties;
(3) Transparency--access must be provided to the methodology,
criteria, and processes used to develop transmission plans;
(4) Information Exchange--the obligations of and methods for
customers to submit data to transmission providers must be described;
(5) Comparability--transmission plans must meet the specific
service requests of transmission customers and otherwise treat
similarly-situated customers (e.g., network and retail native load)
comparably in transmission system planning;
(6) Dispute Resolution--an alternative dispute resolution process
to address both procedural and substantive planning issues must be
included;
(7) Regional Participation--there must be a process for
coordinating with interconnected systems;
(8) Economic Planning Studies--study procedures must be provided
for economic upgrades to address congestion or the integration of new
resources, both locally and regionally; and
(9) Cost Allocation--a process must be included for allocating
costs of new facilities that do not fit under existing rate structures,
such as regional projects.
Petitioners have requested rehearing and clarification regarding
certain of these principles, which we address in turn.
a. Coordination
182. In order to satisfy the coordination principle, transmission
providers must provide stakeholders the opportunity to participate
fully in the planning process. The purpose of the coordination
requirement is to eliminate the potential for undue discrimination in
planning by opening appropriate lines of communication between
transmission providers, their transmission-providing neighbors,
affected state authorities, customers, and other stakeholders. The
planning process must provide for the timely and meaningful input and
participation of customers regarding the development of transmission
plans, allowing customers to participate in the early stages of
development.
Requests for Rehearing and Clarification
183. EPSA and TDU Systems argue that, under Order No. 890,
transmission providers inappropriately retain veto rights over the
decision as to which upgrade projects to include in transmission plans.
These petitioners acknowledge that the transmission provider has the
ultimate obligation to comply with its tariff, but argue that those
tariff obligations be fulfilled in a way that allows for full and equal
participation of customers. EPSA argues that transmission providers
should be obligated to consider consensus positions, to present to the
Commission or its designee minority opinions that have been excluded,
and to explain why consensus proposals that have been disregarded will
not be converted into actual plans to expand or reduce constraints on
the system. TDU Systems request that transmission providers be required
to post on their Web sites a record of the transmission planning
decisions that reflect the views and votes of all participants to that
process. TDU Systems argue that this would enable the Commission to
determine whether the plan reflects consensus among stakeholders and
the needs of customers, as opposed to the unilateral determinations of
the transmission providers. NRECA asks the Commission to clarify that
LSEs in particular have the opportunity to be an integral and equal
part of the regional planning process from the beginning of the process
to its end, including implementation of the regional participation
principle.
184. NRECA argues that comparability requires that LSEs have equal
weight in decision-making. Otherwise, NRECA contends that transmission
providers will continue to have the opportunity and right to
discriminate. NRECA expresses concern that transmission providers will
be able to develop the basic criteria, assumptions, and data that
underlie transmission plans on their own and merely present the results
to customers after the fact. NRECA asks the Commission to clarify that
public utility transmission providers may not arbitrarily,
deliberately, or
[[Page 3006]]
discriminatorily disregard the input of LSE customers at any stage in
the development and drafting of the transmission plan and modify the
pro forma Attachment K to reflect that LSEs will be an integral part of
the planning process.
185. With regard to small LSE customers, NRECA asks the Commission
to clarify that the new requirement that transmission providers develop
and implement joint planning processes does not leave customers that
lack the resources to fully participate in the planning process in a
worse position than they were in under Order No. 888. NRECA states
that, under Order No. 888, transmission providers were required to plan
and expand their systems to meet the needs of all network customers and
long-term point-to-point customers. NRECA contends that the new joint
planning requirement could be read to allow transmission providers to
refuse to consider these customers' needs if they are unable to
participate fully in the transmission planning process. NRECA suggests
that participation in the planning process be an opportunity for load-
serving customers, not an obligation, and that transmission providers
be required to plan for those that are unable to fully participate.
186. Constellation requests that the Commission clarify that it
will closely monitor the planning process to ensure that reforms are
implemented in a meaningful way and that customers have the ability to
truly participate in the process. Williams requests that the planning-
related requirements of Order No. 890 be augmented to require a written
record of stakeholder input, in order to guarantee informed
consideration and debate of non-transmission provider proposals.
187. EEI seeks clarification that transmission providers may adopt
restrictions on the disclosure of CEII in the context of transmission
planning. EEI argues that login requirements and nondisclosure
agreements may not provide sufficient protection for CEII. EEI suggests
that transmission providers be allowed to adopt the Critical
Infrastructure Protection (CIP) reliability standards for the
disclosure of CEII that the Commission adopts in Docket No. RM06-22-
000, Mandatory Reliability Standards for Critical Infrastructure
Protection.
Commission Determination
188. The Commission affirms the decision in Order No. 890 not to
require the development of transmission plans on a co-equal basis with
customers. Transmission planning is the tariff obligation of the
transmission provider, and the pro forma OATT planning process adopted
in Order No. 890 is the means to see that it is carried out in a
coordinated, open, and transparent manner. It would not be appropriate
to allow customers and others that do not bear the responsibility for
tariff compliance to have co-equal control over the planning process.
We reiterate, however, that the planning process must provide for the
timely and meaningful input and participation of all interested
customers and other stakeholders in the development of transmission
plans. Customers and other stakeholders therefore must have the
opportunity to participate at the early stages of the development of
the transmission plan, rather than merely given an opportunity to
comment on transmission plans that were developed in the first instance
without their input.
189. We disagree that the additional processes proposed by EPSA,
TDU Systems, and Williams are necessary at this time to ensure that
transmission providers do not unduly discriminate in the performance of
their planning responsibilities. Customers and other stakeholders have
been given a meaningful opportunity to participate in the planning
process and to voice their concerns, not a formal ``vote'' on the
transmission plan. While we would not consider it reasonable for the
transmission provider to act in an arbitrary fashion by simply ignoring
the comments and concerns of interested parties, we do not believe it
appropriate at this time to adopt additional procedural mechanisms to
measure or track the views of those participants in the planning
process. Should disputes arise, they should first be addressed through
the dispute resolution process set forth in the transmission provider's
Attachment K and then, if necessary, to the Commission's attention
through a complaint or other appropriate procedural mechanism.
190. With regard to participation by small LSEs in planning
activities, we reiterate that the planning process adopted in Order No.
890 is intended to supplement, not replace, the transmission provider's
obligations under section 28.2 of the pro forma OATT to plan for the
transmission needs of its network customers on a comparable basis and
in accordance with Good Utility Practice, as well as the obligation to
construct new facilities pursuant to sections 13.5 and 15.4 of the pro
forma OATT to meet the service requests of its long-term point-to-point
customers. Transmission providers are therefore required to craft a
planning process that allows for a reasonable and meaningful
opportunity for those that are interested and able to meet and
otherwise interact with the transmission provider.\74\ Notwithstanding
a smaller LSE's inability to participate in the additional processes
implemented in compliance with Order No. 890, the transmission provider
still must fulfill its network service obligation to that customer.
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\74\ See Order No. 890 at P 453.
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191. In response to EEI, we clarify that, in addition to login
requirements and nondisclosure agreements, transmission providers may
adopt further restrictions on the distribution of CEII consistent with
any CIP reliability standards that the Commission may adopt in Docket
No. RM06-22-000.
b. Openness
192. In order to satisfy the openness principle, transmission
planning meetings must be open to all affected parties including, but
not limited to, all transmission and interconnection customers, state
commissions and other stakeholders. The Commission recognized in Order
No. 890 that it may be appropriate in certain circumstances, such as a
particular meeting of a subregional group, to limit participation to a
relevant subset of these entities. The Commission emphasized, however,
that the overall development of the plan must remain open.
Requests for Rehearing and Clarification
193. TDU Systems argue that any condition under which a
transmission planning meeting could be limited so as to exclude certain
customers or stakeholders must be explicitly set forth in the
transmission provider's Attachment K. Otherwise, TDU Systems contend
the transmission provider will retain undue discretion over who is
allowed to participate in meetings.
Commission Determination
194. The Commission agrees with TDU Systems that the circumstances
under which participation in a planning meeting is limited should be
clearly described in the transmission provider's Attachment K planning
process. All affected parties must be able to understand how, and when,
they are able to participate in planning activities.
c. Transparency
195. In order to satisfy the transparency principle, transmission
providers must disclose to all customers and other stakeholders the
basic criteria, assumptions, and data that underlie their transmission
system plans. The Commission concluded that this
[[Page 3007]]
information should enable customers, other stakeholders, or an
independent third party to replicate the results of planning studies
and thereby reduce the incidence of after-the-fact disputes regarding
whether planning has been conducted in an unduly discriminatory
fashion. Among other things, the Commission required transmission
providers to make available information regarding the status of
upgrades identified in their transmission plans in addition to the
underlying plans and related studies.
Requests for Rehearing and Clarification
196. TDU Systems ask the Commission to clarify that transmission
providers, and transmission-owning members of an RTO or ISO, must
provide customers and other stakeholders with base case and change case
data. TDU Systems contend that this would be consistent with the
Commission's goal of allowing stakeholders to replicate the results of
planning studies and, in their view, would virtually eliminate disputes
regarding whether planning has been conducted in an unduly
discriminatory fashion.
197. TAPS questions whether the Standards of Conduct would trigger
the full functional separation requirement for a non-public utility
transmission provider participating in the planning process. TAPS
contends that both transmission and generation functions of a non-
public utility transmission provider could participate in planning
activities, consistent with the Standards of Conduct, so long as all
information used in transmission planning is made available to all
participants. If the Commission disagrees, TAPS asks that new
mechanisms be adopted to assure information is not abused, independent
from the Standards of Conduct and existing Standards of Conduct waivers
that do not inhibit the participation of non-public utility
transmission providers in the planning process. TAPS suggests that any
entity be allowed to participate in the regional planning process if it
establishes procedures defining which employees/consultants may receive
confidential transmission and planning information and prohibiting such
employees/consultants from sharing that information with the entity's
wholesale merchant personnel.
198. Old Dominion requests that the Commission adopt performance
metrics governing transmission planning in addition to reports
regarding the status of upgrades. Old Dominion suggests that the
Commission specifically require transmission providers to report on the
progress and construction of all upgrades and facilities in the
transmission plan.
Commission Determination
199. In Order No. 890, the Commission required transmission
providers to disclose to all customers and other stakeholders the basic
criteria, assumptions, and data that underlie their transmission system
plans.\75\ To the extent necessary, we clarify in response to TDU
Systems that this includes disclosure of transmission base case and
change case data used by the transmission provider. These are basic
assumptions necessary to adequately understand the results reached in a
transmission plan.
---------------------------------------------------------------------------
\75\ See id. at P 471.
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200. With regard to management of non-public information by non-
public utility transmission providers, we reiterate that the
reciprocity obligation requires non-public utility transmission
providers to abide by the Standards of Conduct or obtain waiver of
them.\76\ Although we recognize that compliance with the Standards of
Conduct can impose costs on small entities, an open planning process
cannot be fully successful if certain entities (whether jurisdictional
or nonjurisdictional) can use planning-related information to obtain an
undue advantage. The Commission therefore explained in Order No. 890
that it may be necessary to revisit waivers of the Standards of Conduct
granted to certain non-public utility transmission providers in the
past.\77\ The Commission declined to alter such waivers on a generic
basis in Order No. 890 and we affirm that decision here.
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\76\ See Order No. 888-A at 30,286.
\77\ See Order No. 890 at P 474.
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201. As TAPS notes, many of the concerns regarding management of
non-public information shared in the planning process can be alleviated
by simultaneous disclosure of that information to all participants.
Moreover, the Standards of Conduct govern the relationship and exchange
of information between transmission providers and their marketing or
energy affiliates. Entities that do not own, operate or control
transmission facilities, and who are not affiliated with transmission
providers, are not subject to the Standards of Conduct. We believe
establishment of new mechanisms to manage the sharing of non-public
planning information by transmission providers subject to the Standards
of Conduct would be premature and more appropriately addressed in any
proceeding in which the revocation of a Standards of Conduct waiver is
considered.
202. We also decline to adopt additional performance metrics
governing transmission planning. The Commission required in Order No.
890 for transmission providers to make available information regarding
the status of upgrades identified in their transmission plans.\78\
Customers and other stakeholders that are interested in the
implementation of the transmission plan will be able to monitor this
information to gather information regarding the progress and
construction of upgrades and facilities. The Commission does not
believe further reporting requirements are necessary at this time to
keep interested parties informed regarding the status of upgrades
identified in a transmission plan.
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\78\ See id. at P 472.
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d. Information Exchange
203. In order to satisfy the information exchange principle,
transmission providers must develop guidelines and a schedule for the
submittal of information in consultation with their network and point-
to-point customers. The Commission stressed that information collected
by transmission providers to provide transmission service to their
native load customers must be transparent and equivalent information
must be provided by transmission customers to ensure effective planning
and comparability. Point-to-point customers were also required to
submit any projections they have of a need for service over the
planning horizon and at what receipt and delivery points.
Requests for Rehearing and Clarification
204. E.ON U.S. requests that the Commission clarify that all
entities seeking comparable treatment for transmission planning
purposes, including any non-public utilities, must share their cost
information with the transmission provider, as needed for planning
purposes. E.ON U.S. contends that it must have access to information
regarding all of its customers' dispatch and transmission costs in
order to implement joint planning as envisioned by Order No. 890. E.ON
U.S. acknowledges that this information would need to be treated as
competitively sensitive and shielded from the transmission provider's
merchant function employees.
205. Duke seeks clarification that projections of a point-to-point
customer's anticipated needs do not have to be included in the models
[[Page 3008]]
serving as the predicate of the transmission plan. Duke agrees that,
while projected uses may be helpful in understanding the scope of the
potential need for future upgrades, only reservations impose an
obligation on the transmission provider.
Commission Determination
206. The Commission clarifies in response to E.ON U.S. that, within
the context of transmission planning, customers should only be required
to provide cost information for transmission and generation facilities
as necessary for the transmission provider to perform economic planning
studies requested by the customer. If stakeholders request that a
particular congested area be studied, they must supply relevant data
within their possession to enable the transmission provider to
calculate the level of congestion costs that is occurring in the near
future.\79\ This may necessarily involve customers providing their cost
information. As E.ON U.S. notes, transmission providers must maintain
the confidentiality of this information, protecting it from
distribution to employees of the merchant function and its affiliates.
Transmission providers must clearly define in their Attachment K the
information sharing obligations placed on customers in the context of
economic planning.
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\79\ See id. at P 550. The Commission also required the
transmission provider's merchant function to provide any information
necessary for economic planning studies (e.g., redispatch cost
information).
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207. We clarify in response to Duke that good faith projections of
anticipated point-to-point uses of the transmission system are intended
only to give the transmission provider additional data to consider in
its planning activities. The Commission did not intend to suggest in
Order No. 890 that such projections be treated as a proxy for actual
reservations. Even though they are not the equivalent of reserved uses
of the system, such projections could, for example, provide planners
with likely scenarios for new investment.
e. Comparability
208. In order to satisfy the comparability principle, transmission
providers must develop, after considering the data and comments
supplied by customers and other stakeholders, a transmission system
plan that (1) meets the specific service requests of its transmission
customers and (2) otherwise treats similarly-situated customers (e.g.,
network and retail native load) comparably in transmission system
planning. The Commission also required that customer demand resources
be considered on a comparable basis to the service provided by
comparable generation resources where appropriate.
Requests for Rehearing and Clarification
209. E.ON U.S. argues that the comparability principle poses a
dilemma for vertically-integrated utilities in that the utility must
engage in least cost planning at the state level, but is required to
engage in comparable planning at the federal level. E.ON U.S. questions
whether comparability requires the transmission provider to include all
customer-identified projects in its plan or whether the transmission
provider must merely consult with customers regarding their projects.
E.ON U.S. also objects to treating a non-public utility customer
comparably to its own native load in instances when the non-public
utility customer fails to do the same in its own transmission planning
activities. E.ON U.S. requests that the Commission clarify that public
utilities are not required to include non-public utilities in
transmission planning to the extent a non-public utility has not
adopted the transmission planning principles of the pro forma OATT.
210. REPIO argue that planning processes must be clear to ensure
that transmission providers fairly consider and implement the best
alternatives among transmission, generation, and demand response
options. To that end, REPIO ask the Commission to make explicit the
requirement that all resource options be given technology neutral
treatment.
211. Areva, however, argues that transmission providers must be
required to do more than simply include demand resources in the
planning process, arguing that the Commission failed to adequately
encourage the use of alternative technologies as required by section
1223 of EPAct 2005. Areva contends that the Commission erred in failing
to provide new opportunities for advanced technologies in the energy
markets, particularly demand response resources. Areva argues it is
inadequate to merely allow participation of comparable demand-side
resources and, instead, the Commission must take the steps necessary to
promote integration of advanced technologies in the planning process,
including the assessment of penalties for failure to include such
technologies in transmission plans and, ultimately, on the transmission
grid. If the Commission declines to do so, Areva contends that the
Commission at a minimum should require transmission providers to report
their consideration of advanced technologies in their planning process,
highlight uses of such technologies in their resulting transmission
plan, or report to the Commission why such technologies were excluded
from the resulting transmission plan.
212. TDU Systems, however, ask the Commission to confirm that
demand resources can only substitute for truly comparable generation
resources in the planning process. TDU Systems state that demand
resources are, for example, non-dispatchable and can be reasonably
substituted only for equivalent non-dispatchable blocks of energy. TDU
Systems ask the Commission to establish criteria for determining
whether demand resources are comparable to generation resources for
purposes of consideration in the transmission plan or direct
transmission providers to develop such criteria in their Attachment K
proposals.
Commission Determination
213. Comparability requires that the interests of transmission
providers and their similarly-situated customers be treated on a
comparable basis in the transmission planning process.\80\ We do not
believe that this creates a conflict with least cost planning at the
state level. Comparability simply requires that a transmission provider
engage in comparable planning for its similarly-situated customers. The
transmission provider retains discretion as to which solutions to
pursue. Transmission providers are therefore not required to include
all customer-identified projects in its plan, so long as similarly-
situated customers are given comparable consideration.
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\80\ See id. at P 494.
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214. With regard to non-public utility transmission providers, we
reiterate our expectation of participation in the planning processes
established pursuant to Order No. 890 consistent with their reciprocity
obligations.\81\ Reciprocity dictates that non-public utility
transmission providers that take advantage of open access due to
improved planning should be subject to the same requirements as
jurisdictional providers. A non-public utility transmission provider
with reciprocity obligations that declines to adopt a planning process
that complies with Order No. 890 therefore may not be considered to be
providing reciprocal transmission service and may be at risk of being
denied open access transmission services by a public utility
transmission provider. We will consider on a case-by-case basis how a
transmission provider should treat for planning purposes a non-public
utility
[[Page 3009]]
transmission provider that fails to implement a planning process that
fulfills the requirements of Order No. 890.\82\
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\81\ See id. at P 441.
\82\ As the Commission noted in Order No. 890, the Commission
may exercise its authority under section 211A on a case-by-case
basis if we find on the appropriate record that non-public utility
transmission providers are not participating in the planning
processes required therein. See id. at P 441.
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215. We disagree with Areva that the transmission planning process
required in Order No. 890 is inconsistent with section 1223 of EPAct
2005.\83\ The Commission made clear in Order No. 890 that advanced
technologies and demand-side resources must be treated comparably where
appropriate in the transmission planning process and, thus, the
transmission provider's consideration of solutions should be technology
neutral. We believe that the reforms adopted in Order No. 890 are
sufficient to ensure comparable consideration of such technologies in
transmission planning and, therefore, we decline to impose the type of
special penalties proposed by Areva.
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\83\ We note that, in addition to the reforms adopted in Order
No. 890, the Commission is taking steps in other proceedings to
encourage the deployment of advanced technologies as required by
section 1223 of EPAct 2005. See, e.g., Promoting Transmission
Investment through Pricing Reform, Order No. 679, 71 FR 43294 (July
31, 2006), FERC Stats & Regs. ] 31,222 at P 302 (2006), order on
reh'g, Order No. 679-A, 72 FR 1152 (Jan. 10, 2007), FERC Stats. &
Regs. ] 31,236 (2007), order on reh'g, Order No. 679-B, 119 FERC ]
61,062 (2007).
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216. We disagree with TDU Systems that comparability requires that
generation resources and demand resources be subject to the same
operational parameters in every circumstance. Treating similarly-
situated resources on a comparable basis does not necessarily mean that
the resources are treated the same. As part of its Attachment K
planning process, each transmission provider is required to identify
how it will treat resources on a comparable basis and, therefore,
should identify how it will determine comparability for purposes of
transmission planning.
f. Dispute Resolution
217. In order to satisfy the dispute resolution principle,
transmission providers must develop a dispute resolution process to
manage disputes that arise from the Attachment K planning process. The
Commission stated that the dispute resolution process must address both
procedural and substantive planning issues, as the purpose for
including a dispute resolution process is to provide a means for
parties to resolve all disputes related to the planning process before
turning to the Commission.
Requests for Rehearing and Clarification
218. TDU Systems ask the Commission to clarify that transmission
providers must develop a dispute resolution process in collaboration
with transmission customers and other stakeholders. TDU Systems argue
that this clarification is necessary to assure that ``the shape of the
table'' for dispute resolution is not fashioned to favor one side.
219. Duke asks the Commission to clarify whether alternative
dispute resolution (ADR) will become a vehicle to challenge the
transmission plan ultimately adopted by the transmission provider. Duke
questions any intent by the Commission to exercise authority to approve
or disapprove a transmission plan. Duke argues that ADR should not be
used to substantively second guess a vertically-integrated transmission
provider's plan. If ADR is intended to address substantive planning
issues, Duke asks the Commission to clearly delineate the scope of
those issues. Duke also asks the Commission to state the basis for any
determination that ADR could be used to require changes to a
transmission plan that would have the effect of fashioning binding
obligations to build or not to build any particular facility in
contravention of the transmission plan.
Commission Determination
220. As with any aspect of the transmission provider's Attachment K
compliance filing, the Commission encourages stakeholder involvement in
the development of an appropriate dispute resolution process to govern
planning-related disputes. The Commission will carefully review each
compliance filing to ensure that the proposed planning process is
consistent with the principles and other requirements of Order No. 890.
Any stakeholder that has concerns regarding the dispute resolution
mechanism proposed by a transmission provider, or any other aspect of
the compliance filing, may bring them to the Commission's attention on
review of the proposal.
221. We disagree with Duke that the scope of this dispute
resolution mechanism is limited to procedural issues. As the Commission
explained in Order No. 890, the dispute resolution process should be
available to address all disputes related to the planning process, both
procedural and substantive.\84\ This does not mean, as Duke implies,
that any changes to the plan that may result from dispute resolution
procedures become a binding obligation to build. In requiring a dispute
resolution process for planning-related disputes, the Commission is not
asserting any greater authority than it otherwise has to ensure that
transmission providers comply with their tariff obligations to expand
their systems to meet the needs of their customers. The dispute
resolution process therefore does not change the rights or obligations
otherwise established in the pro forma OATT. As we reiterate above, the
Attachment K planning process does not place an affirmative obligation
on the transmission provider to build upgrades identified in a plan.
The tariff requirements regarding the construction of new facilities
are covered in other portions of the pro forma OATT, as discussed
above.
---------------------------------------------------------------------------
\84\ See id. at P 501.
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g. Regional Participation
222. In order to satisfy the regional participation principle,
transmission providers must coordinate with interconnected systems to
(1) share system plans to ensure that they are simultaneously feasible
and otherwise use consistent assumptions and data and (2) identify
system enhancements that could relieve congestion or integrate new
resources. The Commission explained that the specific features of the
regional planning effort should take account of and accommodate, where
appropriate, existing institutions, as well as physical characteristics
of the region and historical practices.
Requests for Rehearing and Clarification
223. TDU Systems ask the Commission to clarify that the regional
participation principle requires both transmission providers and other
stakeholders to be actively involved in regional planning activities.
TDU Systems contend that some language in Order No. 890 could be read
to limit regional coordination to transmission providers.\85\
---------------------------------------------------------------------------
\85\ Citing id. at P 523.
---------------------------------------------------------------------------
224. National Grid asks the Commission to expand the regional
participation principle to expressly require regions to adopt
interregional planning processes subject to the same nine principles
applicable to individual regions. National Grid argues that there will
be little improvement in the area of interregional planning, and that
disputes will continue to arise, in the absence of generic action by
the Commission.
[[Page 3010]]
225. EPSA suggests that Commission staff be designated to attend
the development of all regional planning processes in non-RTO areas, in
order to ensure adequate and timely oversight and accountability during
the development stage, as well as to ensure that all stakeholders have
a viable chance to participate in the development of their own regional
planning processes.
Commission Determination
226. The Commission clarifies in response to TDU Systems that,
while the obligation to engage in regional coordination is directed to
transmission providers, participation in such processes is not limited
to transmission providers. In Order No. 890, the Commission required
transmission providers to develop a planning process that facilitates
regional participation and required that process, in turn, to be open
to all interested customers and stakeholders. In response to National
Grid, we emphasize that effective regional planning should include
coordination among regions. As the Commission explained in Order No.
890, the identification of relevant regions and sub-regions will depend
on the integrated nature of the power grid and the particular
reliability or resource issues affecting individual regions and sub-
regions.\86\ Each of these regions and sub-regions should coordinate as
necessary to share data, information and assumptions to maintain
reliability and allow customers to consider resource options that span
the regions.
---------------------------------------------------------------------------
\86\ See id. at P 627.
---------------------------------------------------------------------------
227. We decline EPSA's suggestion to direct Commission staff to
attend the development of all regional planning processes in non-RTO
areas. Commission staff has organized and attended a total of seven
transmission planning technical conferences around the country, and
engaged in numerous other meetings, phone calls and discussions, in
order to assist transmission providers and customers in the development
of planning processes that comply with the planning requirements of
Order No. 890.\87\ Transmission providers and stakeholders alike
actively participated in these conferences. Any concerns regarding the
inability of interested parties to participate in the development
process can be raised on Commission review of the Attachment K
compliance filings.
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\87\ The staff technical conferences were held on: June 4-7,
2007 in Little Rock, AR and October 1-2, 2007 in Atlanta, GA,
covering the Southeast including Southwest Power Pool and its
members; June 13, 2007 in Park City, UT, covering the Northwest and
June 26, 2007 in Phoenix, AZ, covering the Southwest and California,
as well as October 23-24, 2007 in Denver, CO, covering both of these
regions; and June 28-29, 2007 in Pittsburgh, PA and October 15-16,
2007 in Boston, MA, covering the ISO New England, NYISO, PJM, MISO,
and Mid-Continent Area Power Pool subregions.
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h. Economic Planning Studies
228. In order to satisfy the economic planning studies principle,
transmission providers must take into account both reliability and
economic considerations in their Attachment K planning processes. The
Commission stated that the purpose of this principle is to ensure that
customers may request studies that evaluate potential upgrades and
other investments that could reduce congestion or integrate new
resources and loads on an aggregated or regional basis, and not to
assign cost responsibility for any investments or otherwise determine
whether they should be implemented.\88\ The Commission determined that
customers should be permitted to choose the studies that are of the
greatest value to them, directing transmission providers to develop a
means to allow the transmission provider and stakeholders to cluster or
batch requests for economic planning studies so that the transmission
provider may perform the studies in the most efficient manner.
Customers must be given the right to request a defined number of high
priority studies annually, the costs of which would be recovered as a
part of the overall pro forma OATT cost of service.
---------------------------------------------------------------------------
\88\ The Commission addressed the issue of cost allocation in a
separate principle, discussed below.
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Requests for Rehearing and Clarification
229. TDU Systems ask the Commission to clarify that the expansion
of economic planning required in Order No. 890 to include integration
of new resources and loads did not supplant the need to study both
short-term and long-term congestion. TDU Systems further argue that any
measure of congestion in the economic study process must be based on
total gross congestion rather than hedgeable congestion, which they
argue is unrealistic. TDU Systems state that in PJM, for example,
congestion includes only that which cannot be hedged through financial
instruments. TDU Systems contend that this ignores the significant
costs of purchasing the financial instruments necessary to hedge the
congestion and that gross congestion more accurately reflects what load
pays for congestion.
230. TDU Systems also ask the Commission to clarify that each
transmission provider must specify in its Attachment K the process for
requesting and selecting economic planning studies and the number of
high priority studies that will be paid for by the transmission
provider. TDU Systems argue that the economic study process, including
selection of which studies to perform, must be developed in
collaboration with customers and other interested stakeholders. TDU
Systems, as well as NRECA, suggest that the high priority studies only
include those requested by non-affiliated customers so that the
economic planning process is not usurped by the transmission provider
and its affiliates.
231. AWEA asks the Commission to require transmission providers to
engage in economic planning of upgrades to address the lumpiness of
transmission investments. AWEA argues that the needs of native load
groups, multiple generation projects, and load centers cannot be
optimized unless they are combined in a single transmission plan. AWEA
contends that comparability requires planning to provide capacity for
OATT customers so that the cost of large, lumpy upgrades are not all
assigned to single projects.
232. EEI requests clarification that the stakeholders' right to
designate high priority studies applies to stakeholders as a group, not
to individual stakeholders. EEI asserts that allowing individual
stakeholders to designate specified numbers of studies would be
impractical and inconsistent with the goal of an aggregated or regional
approach to planning. Entergy asks the Commission to clarify that
economic studies must be related to congestion issues affecting a
stakeholder and not simply attempts to obtain competitive sensitive
information about another party's resources and loads. Entergy suggests
that a party requesting a study be required to explain the basis for
its request and how the study relates to its own transmission service
needs.
233. MISO, NYISO and National Grid ask the Commission to clarify
that, within an RTO or ISO, requests for congestion studies must be
made and approved through existing stakeholder processes. Otherwise,
National Grid argues that studies may be tailor-made to the parochial
interests of the requestor with limited subregional scope, which in its
view would inhibit the regional planning process and tax RTO and ISO
resources. NYISO requests further clarification that transmission-
owning members of an RTO or ISO are not required to perform separate,
[[Page 3011]]
individual congestion studies at the request of customers.
234. Southern argues that the economic planning requirements of
Order No. 890 should be based on the Commission's jurisdiction to
ensure just and reasonable rates, since the information from such
studies could facilitate customers' ability to optimize their future
transmission service. Southern contends that neither Good Utility
Practice nor comparability support adoption of the economic study
requirements of Order No. 890. Southern states that its transmission
function planners perform no congestion analysis and, instead, plan the
system to satisfy reliability requirements and to meet the needs of
firm transmission customers.
Commission Determination
235. The Commission affirms the decision in Order No. 890 to allow
stakeholders the right to request a defined number of high priority
studies annually to address congestion and/or the integration of new
resources or loads.\89\ The expansion of the economic planning
principle in Order No. 890 did not supplant the need to study both
short-term and long-term congestion, if requested by a stakeholder, as
TDU Systems suggest. Similarly, the choice to study hedgeable or gross
congestion is the choice of the requesting stakeholder or group of
stakeholders. The intent of the economic planning principle is to allow
stakeholders, and not the transmission provider, to identify the
studies that are of the greatest value to them. This provides
sufficient flexibility to address customer needs, including the study
of large, lumpy transmission projects, as requested by AWEA.
---------------------------------------------------------------------------
\89\ Order No. 890 at P 547.
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236. We agree with petitioners that the transmission provider's
Attachment K must clearly describe the process by which economic
planning studies can be requested and how they will be prioritized.\90\
We also agree that stakeholders as a group have the right to request
the defined number of high priority studies to be paid for by the
transmission provider.\91\ As a result, transmission providers must
develop a means to allow the transmission provider and customers to
cluster or batch requests for economic planning studies so that the
transmission provider may perform the studies in the most efficient
manner. By limiting the economic planning principle to a defined number
of high priority studies annually, the Commission did not intend to
preclude stakeholders from requesting additional studies. To provide
appropriate financial incentives, the stakeholder(s) requesting such
additional studies would be responsible for paying the cost of such
studies.\92\
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\90\ RTOs and ISOs may continue to use existing stakeholder
processes to identify which economic planning studies will be of
most benefit to the region, provided such processes are otherwise
consistent with the requirements of Order No. 890.
\91\ See id. at P 547.
\92\ See id. at P 546.
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237. We decline to generically limit the scope of economic planning
studies as requested by Entergy. Studies may be requested to address
congestion issues or the integration of new resources/loads. The
limited number of high priority studies available should restrict the
ability of stakeholders to use these studies for other purposes, since
stakeholders and the transmission providers will be working together to
determine which studies will be pursued. We also reject petitioners'
suggestion that the requests made by a transmission provider's
affiliates for economic planning studies should not count toward the
defined number of high priority studies. The transmission provider's
affiliates should be treated like any other stakeholder and, therefore,
their requests for studies should be considered comparably, pursuant to
the process outlined in the transmission provider's Attachment K.
238. We clarify in response to NYISO that it is the transmission
provider's obligation to perform economic planning studies, just as it
is the transmission provider's obligation to comply with other aspects
of the planning process required in Order No. 890. As we explain above,
RTOs and ISOs have flexibility in determining how to fulfill their
planning-related obligations and may delegate certain responsibilities
to their transmission-owning members or otherwise incorporate the
processes of their members into the RTO/ISO planning process. To the
extent an RTO or ISO delegates any of its responsibilities in the
context of economic planning, it will be the obligation of the RTO or
ISO to ensure ultimate compliance with the requirements of Order No.
890.
239. We disagree with Southern that the Commission may only require
transmission providers to undertake economic planning studies pursuant
to its authority to ensure just and reasonable rates. Consistent with
our authority under FPA section 206, the Commission acted in Order No.
890 to limit the opportunities for undue discrimination in the area of
transmission planning and to ensure that comparable service is provided
by all public utility transmission providers. As the Commission
explained in Order No. 890, a prudent vertically-integrated
transmission provider will plan not only to maintain reliability, but
also consider whether transmission upgrades or other investments can
reduce the overall costs of serving native load.\93\ To represent Good
Utility Practice and provide comparable service, the transmission
planning process under the pro forma OATT therefore must consider both
reliability and economic considerations.
---------------------------------------------------------------------------
\93\ See id. at P 542.
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240. Southern states merely that its transmission planners do not
perform congestion analyses in particular, not that they disregard
economics in the planning of their system. Prudent vertically-
integrated transmission providers take into consideration whether
upgrades or other investments could allow them to meet the needs of
their customers on a more economic basis. Through the economic planning
principle, we simply require Southern, and other transmission
providers, to make available to their customers services that are
comparable to those they are performing on behalf of their native load.
We therefore affirm the decision in Order No. 890 to require
transmission providers to perform economic planning studies at the
request of their stakeholders.
i. Cost Allocation for New Projects
241. In order to satisfy the cost allocation principle,
transmission providers must address in their Attachment K planning
processes the allocation of costs of new facilities. These cost
allocation methodologies are intended to apply to projects that do not
fit under existing rate structures, such as regional projects involving
several transmission owners or economic projects that are identified
through the study process, rather than projects built in response to
individual requests for service. The Commission declined to impose a
particular allocation methodology for such projects and, instead,
identified three factors to be considered upon review of cost
allocation proposals. First, we consider whether a cost allocation
proposal fairly assigns costs among participants, including those who
cause them to be incurred and those who otherwise benefit from them.
Second, we consider whether a cost allocation proposal provides
adequate incentives to construct new transmission. Third, we consider
whether the proposal is generally supported by state authorities and
participants across the region.
[[Page 3012]]
Requests for Rehearing and Clarification
242. PSEG questions whether the Commission intended in Order No.
890 to mandate the funding of economic projects through the cost
allocation methodology developed as part of the transmission provider's
planning process. PSEG argues that this would be inappropriate since
certain transmission providers, such as NYISO, currently only conduct
reliability planning, not economic planning. PSEG argues that the most
transmission providers should be obligated to do is present information
so that market participants may respond to economic issues. In its
view, introduction of regulated transmission solutions in response to
economic enhancements destroys incentives for private investment and
precludes the possibility of other market-based solutions, such as
generation and demand side management, from providing a more efficient
solution. PSEG objects to the Commission's reliance on the PJM ``market
efficiency'' proposal, arguing that the Commission's action in that
proceeding was conditioned on PJM submitting a compliance filing to
clarify aspects of its proposal.\94\
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\94\ Citing id. at P 545 (citing PJM Interconnection, LLC, 117
FERC ] 61,218 (2006), reh'g pending).
---------------------------------------------------------------------------
243. To the extent the Commission requires ratepayer funding of
economic upgrades, PSEG suggests that market participants who are asked
to pay be allowed to vote on acceptance of cost allocations for the
project. PSEG suggests that construction of a project be approved only
if a certain percentage vote in favor of building the project and no
more than a certain percentage vote against building the project. With
regard to reliability upgrades, PSEG argues that there are also
insufficient checks in place to ensure that RTOs and ISOs do not
undertake expensive upgrades to solve a reliability criteria violation
when simpler, less expensive projects may suffice. PSEG therefore
requests that the Commission require that a cost-benefit analysis be
conducted for both reliability and economic transmission projects.
244. TDU Systems argue that the costs of all network upgrades
identified in the transmission plan be allocated and recovered on a
rolled-in basis. TDU System maintain that rolled-in rate treatment for
such upgrades would minimize disputes and encourage expansion by
providing certainty for transmission providers. TDU Systems contend
that failure to mandate rolled-in cost recovery for network upgrades
identified in the transmission plan defaults on the Commission's
obligations under FPA section 217 to promote expansion to support the
ability of LSEs to meet their service obligations.
245. EPSA argues that any cost allocation of economic projects must
be based on clear and balanced economic metrics, calculations, and
assumptions. EPSA objects to any requirement that cost allocation
provisions for economic projects create a funding mechanism for
proponents of such projects, arguing that this would be inconsistent
with the Commission's statements that transmission providers are not
under an obligation to fund or build upgrades identified in the
transmission plan.
246. Old Dominion urges the Commission to clarify Order No. 890 by
elaborating and expanding upon the factors the Commission will consider
in addressing cost allocation for new transmission. Old Dominion
suggests that the following issues be considered in evaluating whether
a cost allocation proposal is reasonable: facilitation of regional
market development; benefits over the life of the facility; reliability
benefits beyond resolution of the triggering reliability violation;
reduction in capacity, energy, and reserve costs from reliability
upgrades; consideration of benefits that may not be readily
quantifiable; need for rate certainty; and, avoidance of rate shock.
Old Dominion argues that elaboration on these factors will help
stakeholders reach consensus on cost allocation issues. Old Dominion
also seeks clarification that the cost allocation principle applies
equally to projects that are built by a single transmission owner, but
that have a regional impact.
247. With regard to interregional cost allocation, Old Dominion and
TDU Systems argue that the Commission should require the cost
allocation criteria identified in the transmission provider's
Attachment K to apply to transmission facilities in one region that
provide benefits to customers in another region.\95\ Old Dominion
contends that omission of cross-border allocation requirements in the
OATT is inconsistent with basic cost causation principles as expressed
in Order No. 890 itself.\96\ TDU Systems argue that regions will
benefit from up-front resolution of cross-border allocation issues,
just as transmission providers benefit from up-front resolution of
regional cost allocation issues.
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\95\ Citing Midwest Ind. Sys. Operator, Inc., 117 FERC ] 61,241
(2006); Midwest Ind. Sys. Operator, Inc., 109 FERC ] 61,243 (2004).
\96\ Citing Order No. 890 at P 559.
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248. E.ON U.S. asks the Commission to clarify that the cost
allocation principle may not be used to shift transmission construction
costs to border utilities that receive no direct benefit from the
construction. E.ON U.S. contends that the transmission customers of
each RTO or ISO already pay for the cost of upgrades through
transmission rates charged by the RTO or ISO.
249. Duke does not object to the cost allocation principle, but
notes the difficulties that have been experienced in reaching consensus
in RTOs and ISOs and asks the Commission to consider delaying the
requirement beyond the 210-day due date if regional consensus cannot be
reached. In the alternative, Duke suggests that transmission providers
be allowed to submit allocation proposals as separate informational
strawmen that will serve as a vehicle for further discussion in the
region.
Commission Determination
250. The Commission affirms the decision in Order No. 890 to
require transmission providers to address in their Attachment K
planning processes cost allocation for new facilities that do not fit
under existing structures. Transmission providers and customers cannot
be expected to support the construction of new transmission unless they
understand who will pay the associated costs. This applies equally to
reliability and economic projects, whether built by a single
transmission owner or through joint ownership. However, mandatory
rolled-in rate treatment for all network upgrades identified in the
transmission plans, as suggested by TDU Systems, is not necessarily
appropriate. The Commission is fulfilling its obligations under FPA
section 217 to support expansion of the grid by requiring transmission
providers to address in their Attachment K processes how costs will be
allocated for reliability and economic projects, which we will address
on a case-by-case basis.
251. We disagree with PSEG's contention that economic projects
should be excluded from the cost allocation provisions of the pro forma
OATT. As the Commission noted in Order No. 890, the issue of cost
allocation is particularly important as applied to economic
upgrades.\97\ Participants seeking to support new transmission
investment need some degree of certainty regarding cost allocation to
pursue that investment. We therefore agree with EPSA that the details
of proposed cost allocation methodologies must be clearly defined,
[[Page 3013]]
but emphasize that adoption of a cost allocation methodology will not
impose an obligation to build. As we reiterate above, identification of
an upgrade (reliability or economic) in the transmission plan does not
trigger an obligation to build under the Attachment K planning process.
Up-front identification of how the cost of a facility will be allocated
will, however, allow transmission providers, customers, and potential
investors to make the decision whether or not to build on an informed
basis.
---------------------------------------------------------------------------
\97\ See id. at P 542.
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252. As explained above, all transmission providers, including RTOs
and ISOs, must undertake economic planning studies at the request of
stakeholders. Within an RTO or ISO, stakeholder processes can be used
to determine whether to pursue either economic or reliability upgrades
and, thus, voting mechanisms such as those suggested by PSEG could be
adopted if stakeholders desire. If the transmission provider or
stakeholders determine that other solutions are superior to
transmission upgrades, they may pursue those solutions instead and
integrate them into the transmission plan. The transmission planning
process established in Order No. 890 does not dictate that particular
investments be made, rather that an open, coordinated, and transparent
process be adopted to govern the decision-making process.
253. We decline to adopt Old Dominion's suggestion to define in
more detail the factors to be considered in evaluating whether a cost
allocation proposal is reasonable. We intend to allow regional
flexibility regarding cost allocation and will consider each proposal
on a case-by-case basis. While we would expect many of the
considerations raised by Old Dominion to be relevant, since they fall
within the three factors identified by the Commission, the merits of
each proposal will be analyzed in light of the facts and circumstances
surrounding the proposal. Similarly, issues regarding cross-border
allocation or the potential shifting of costs to border utilities are
best addressed in the context of a particular proposal.
254. Finally, we deny Duke's request to extend the Attachment K
compliance deadline as it relates to cost allocation proposals. We
acknowledge that resolution of cost allocation issues are difficult, as
are many of the issues raised in the context of transmission planning.
The Commission therefore granted transmission providers an extension of
the Attachment K filing deadline in order to allow for a second round
of staff technical conferences to review progress made on draft
compliance filings.\98\ Commission staff also issued a white paper to
further assist transmission providers in the drafting of Attachment K
tariff language.\99\ We believe that transmission providers have had
adequate time and guidance to complete the drafting of their Attachment
K proposals prior to the revised filing deadline.
---------------------------------------------------------------------------
\98\ See Preventing Undue Discrimination and Preference in
Transmission Service, 120 FERC ] 61,103 (2007).
\99\ Transmission Planning Process Staff White Paper, Docket No
RM05-17-000, et al. (August 2, 2007).
---------------------------------------------------------------------------
j. Additional Issues Relating to Planning Reform
(1) Independent Third-Party Coordinator
255. The Commission declined in Order No. 890 to require the use of
an independent third party coordinator for transmission planning
activities, but encouraged transmission providers and their customers
to explore aspects of planning where the use of an independent
coordinator would be beneficial and to incorporate those aspects in
their planning processes.
Requests for Rehearing and Clarification
256. Old Dominion argues that the Commission erred by failing to
recognize the need for an independent third party to oversee
transmission planning. With regard to RTOs in particular, Old Dominion
seeks confirmation that market monitoring units have the requisite
independence and authority to investigate and address undue influence
in the transmission planning process. Old Dominion asks the Commission
to direct RTOs to include in their compliance filings a description of
the market monitor's ability to identify and address undue influence in
the transmission planning process. Old Dominion argues that the ability
for customers to file a section 206 complaint is insufficient and can
only bring about prospective changes in monitoring, failing to remedy
the potential exercise of transmission market power in transmission
planning.
257. TDU Systems support the decision not to mandate use of a
third-party facilitator in the transmission planning process and seek
clarification that, to the extend a third-party facilitator is used,
related costs can be included in a transmission provider's cost of
service only if all transmission customers agree or if a cost-benefit
analysis supports the use of the facilitator. TDU Systems contend this
would avoid disputes regarding the wisdom of using a third-party
facilitator if a significant segment of transmission customers object.
Commission Determination
258. We disagree with Old Dominion that we did not adequately
address the potential role of an independent third party in
transmission planning in Order No. 890. As the Commission explained,
there may be benefits to be gained from independent third party
oversight, but transmission providers, customers, and other
stakeholders should determine for themselves in developing the
transmission provider's planning process whether, and if so how, to
utilize an independent third party.\100\ This would include
considerations regarding recovery of costs associated with the use of a
third-party in the transmission planning process and, within an RTO,
the role of the market monitor, if any, in that process.
---------------------------------------------------------------------------
\100\ See Order No. 890 at P 567.
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(2) Open Season for Joint Ownership
259. Although the Commission acknowledged in Order No. 890 the
benefits of joint ownership of transmission facilities, the Commission
declined to mandate open season procedures to allow market participants
to participate in joint ownership. The Commission recognized that there
may be reasons, given the complexity of the transmission grid and
changing conditions of supply and demand for power, why any given
facility identified in a transmission plan may not be ultimately
constructed. If a transmission provider declines to construct an
identified upgrade, the Commission encouraged customers and third
parties to consider, either individually or jointly, development and
ownership of a project to the extent consistent with applicable state
law.
Requests for Rehearing and Clarification
260. FMPA asks the Commission to order transmission providers to
make available opportunities to jointly participate in the ownership of
new transmission facilities to achieve the benefits of joint ownership
recognized by the Commission and remedy the discriminatory and
anticompetitive effects of excluding some public power utilities from
ownership. In the alternative, FMPA asks the Commission to take the
lesser step of establishing presumptions that transmission customers
are allowed to jointly invest in new grid transmission facilities and
that transmission providers are not entitled to rate incentives if they
exclude some systems that are willing to
[[Page 3014]]
invest in transmission. FMPA argues that such presumptions will prevent
recalcitrant transmission owners from refusing participation or from
using their control of the grid to extract unreasonable terms and
conditions, while allowing them to protect any legitimate interests
they may have.
261. TDU Systems argue that diversification of ownership of the
grid, facilitated by mandatory open seasons for joint or third-party
ownership, would provide a structural remedy to the vertical market
power enjoyed by many transmission providers. They contend that the
inadequacy of the grid, combined with the unwillingness or inability of
transmission providers to invest in new infrastructure, has allowed
many transmission providers to retain generation dominance on their
systems and unduly discriminate against transmission customers. TDU
Systems argue that FPA sections 205 and 206 give the Commission
adequate authority to mitigate this market power by either requiring
open seasons for joint ownership or third-party ownership or by
conditioning market-based rate authority or incentive rates on
agreements to offer such open seasons.
262. TDU Systems argue that the Commission at a minimum should
require transmission providers to hold open seasons for third-party
construction where a transmission provider is unwilling or unable to
construct a new facility that is identified as needed in the planning
process. TDU Systems further request that the Commission modify the pro
forma OATT to include an explicit obligation to interconnect joint or
third-party facilities constructed in response to projects identified
in the local or regional planning process.
Commission Determination
263. The Commission affirms the decision in Order No. 890 not to
mandate procedures for joint ownership of transmission facilities. We
continue to believe that there are benefits to joint ownership,
particularly for large backbone transmission facilities, and encourage
transmission providers, customers, and third parties to consider joint
development and ownership as appropriate. The Commission acknowledged
in Order No. 890, however, that joint ownership can increase the
complexity of planning and developing a transmission project and we are
sensitive to concerns that formal open seasons can add to that
complexity.\101\ We therefore decline to mandate the generic use of
open seasons or establish presumptions, as suggested by FMPA, regarding
their use.
---------------------------------------------------------------------------
\101\ Id. at P 594.
---------------------------------------------------------------------------
264. We also reject TDU Systems' suggestion that declining to
mandate open seasons for joint ownership leaves the transmission
provider with unmitigated vertical market power. Transmission providers
are required under the OATT to make transfer capability available on a
non-discriminatory basis and to expand their systems as necessary to
accommodate requests for transmission service, including service
associated with new customer-owned transmission facilities. In the
absence of specific evidence of undue discrimination by a transmission
provider, we do not believe mandating open seasons or altering our
incentive rate program is necessary to mitigate market power in the
provision of transmission service. Customers and third parties remain
free to develop and construct facilities as they see fit and, through
the Attachment K planning process, incorporate the development of those
facilities into the transmission plan.
C. Transmission Pricing
1. Energy and Generation Imbalances
a. Tiered Approach to Imbalance Penalties in the OATT
265. In Order 890, the Commission modified Schedule 4 of the pro
forma OATT regarding treatment of energy imbalances and adopted a
separate pro forma OATT schedule (Schedule 9) to govern treatment of
generator imbalances. The Commission determined that charges for both
energy and generator imbalances must follow three principles: (1) The
charges must be based on incremental cost or some multiple thereof; (2)
the charges must provide an incentive for accurate scheduling, such as
by increasing the percentage of the adder above (and below) incremental
cost as the deviations become larger; and (3) the provisions must
account for the special circumstances presented by intermittent
generators and their limited ability to precisely forecast or control
generation levels, such as waiving the more punitive adders associated
with higher deviations.
266. The Commission also determined that the same tiered approach
should be used for both energy and generator imbalances. Imbalances of
less than or equal to 1.5 percent of the scheduled energy (or two
megawatts, whichever is larger) are to be netted on a monthly basis and
settled financially at 100 percent of incremental cost at the end of
each month. Imbalances between 1.5 and 7.5 percent of the scheduled
amounts (or 2 to 10 megawatts, whichever is larger) are to be settled
financially at 90 percent of the transmission provider's system
incremental cost for overscheduling imbalances that require the
transmission provider to decrease generation or 110 percent of the
incremental cost for underscheduling imbalances that require increased
generation in the control area. Finally, imbalances greater than 7.5
percent of the scheduled amounts (or 10 megawatts, whichever is larger)
are to be settled at 75 percent of the system incremental cost for
overscheduling imbalances or 125 percent of the incremental cost for
underscheduling imbalances.
Requests for Rehearing and Clarification
267. TAPS contends that the use of the phrase ``same imbalance'' in
the language of Schedules 4 and 9 is imprecise and could lead to some
confusion. TAPS asks that the Commission amend the language of
Schedules 4 and 9 to be consistent with footnote 387 of Order No. 890,
in which the Commission states that a transmission provider may only
charge the penalty percent adder to the incremental cost for either an
hourly generator imbalance or an hourly energy imbalance for the same
imbalance.\102\ TAPS suggests modifying the first paragraph of Schedule
9 to read: ``The Transmission Provider may charge a Transmission
Customer a penalty for either hourly generator imbalances under this
Schedule or hourly energy imbalances under Schedule 4 for the
imbalances occurring during the same hour, but not both (unless the
imbalances aggravate rather than offset each other).'' TAPS requests
that the similar change be made to corresponding language in Schedule
4.
---------------------------------------------------------------------------
\102\ See id. at P 632, n.387.
---------------------------------------------------------------------------
268. Steel Manufacturers Association argues that the Commission
should abandon the dead band/penalty mechanism for energy imbalances
and adopt instead the basic framework employed in the organized
markets, where a customer pays or is paid the provider's incremental
cost for imbalances. Steel Manufacturers Association contends that, in
the organized markets, the Commission recognizes that pricing
imbalances at the real-time price of energy provides adequate
incentives to ensure that customers schedule accurately. Steel
Manufacturers Association argues that the Commission failed to justify
application of a different policy, i.e., escalating penalties, under
the pro
[[Page 3015]]
forma OATT. Steel Manufacturers Association contends that there is no
evidence of negative reliability impacts in the organized markets due
to the lack of inaccurate scheduling, nor is there evidence of
customers taking advantage of the transmission provider by leaning on
the transmission grid. Steel Manufacturers Association further contends
that similar imbalance pricing policies should apply in both market
structures. Steel Manufacturers Association argues that clearing
imbalances outside of the organized markets at the transmission
provider's marginal cost for the hour is sufficient for that purpose.
If the Commission retains a Schedule 4 with a bandwidth and penalty
structure, Steel Manufacturers Association requests that the Commission
institute a larger bandwidth of, at minimum, 10 percent for small
wholesale customers and discrete retail loads in order to provide some
measure of relief for those customers.
269. Steel Manufacturers Association also requests that end-use
customers that provide ancillary services through demand response be
exempt from imbalance charges for imbalances created as a result of the
use of the demand response. Steel Manufacturers Association contends
that an end-use customer that modifies its usage in real-time, in order
to be price responsive or respond to a system operator's call to
curtail load, will create energy imbalances. If that end-use customer
is assessed a penalty for those energy imbalances, Steel Manufacturers
Association argues that it will have little incentive to provide an
ancillary service such as spinning reserve or regulation through demand
response. Steel Manufacturers Association suggests that the Commission
revise the energy imbalance provisions to encourage, rather than
discourage, demand response.
Commission Determination
270. The Commission affirms the decision in Order No. 890 to adopt
a tiered bandwidth approach for both energy and generation imbalances.
We disagree with Steel Manufacturers Association that simply paying the
transmission provider's incremental cost for energy imbalances would
provide adequate incentives for customers to schedule accurately under
the pro forma OATT. Market structures in place within RTOs and ISOs are
fundamentally different from those in non-RTO/ISO regions. In the
organized markets, system operators generally use a five minute
dispatch with multiple suppliers of imbalance energy responding to
system operator instructions. Suppliers and customers alike are
therefore able to respond to real-time changes in locational prices
that reflect both the cost of energy and congestion, which serves to
discipline transmission customers and generators from deviating from
their instructed level. This is not the case outside of the organized
markets and, therefore, other incentives must be provided to discourage
deviations.
271. We also decline to institute a larger bandwidth or eliminate
the penalty structure for energy imbalances caused by small wholesale
customers or discrete loads. Use of the bandwidths adopted in Order No.
890, with the 2 MW and 10 MW minimums for the first and second penalty
bands, appropriately links increased deviations and potential
reliability impacts on the system while allowing increased tolerance to
smaller customers. We note, moreever, that the 2 MW minimum specified
in Order 890 does allow for a 10 percent bandwidth, as Steel
Manufacturers Association requests, for loads 20 MW or less.
272. We agree with Steel Manufacturers Association, however, that
end-use customers providing an ancillary service through demand
response should generally not be subject to penalties for imbalances
created as a result of providing the ancillary service. In this
respect, customers using demand resources for ancillary services should
not be treated differently from customers using generating units to
provide ancillary services. The mechanisms for addressing the self-
provision or third-party provision of ancillary services have developed
outside the pro forma OATT and we will not disrupt these developments.
Thus, there is no need to revise the pro forma OATT, as Steel
Manufacturers Association suggests, since existing practices for third-
party provided ancillary services should apply to demand resources as
they apply to generating resources.
273. We agree with TAPS that the reference to ``same imbalance'' in
Schedules 4 and 9 could lead to confusion and amend the language of
those schedules accordingly. We revise the language of Schedules 4 and
9 to clarify that the transmission provider may charge a transmission
customer a penalty for either hourly generator imbalances under
Schedule 9 or hourly energy imbalances under Schedule 4 for imbalances
occurring during the same hour, but not both unless the imbalances
aggravate rather than offset each other.
b. Generator Imbalance Penalties
274. The Commission concluded in Order No. 890 that formalizing
generator imbalance provisions in the pro forma OATT will standardize
the future treatment of such imbalances from the wide variety of
generator imbalance provisions that previously existed in various
generator interconnection agreements. Standardizing generator imbalance
provisions, in turn, should lessen the potential for undue
discrimination, increase transparency and reduce confusion in the
industry. The Commission emphasized, however, that it was not
abrogating existing generator imbalance agreements in this rulemaking
proceeding.
275. With regard to intermittent resources, the Commission provided
that such resources are exempt from the third-tier deviation band and
would pay the second-tier deviation band charges for all deviations
greater than the larger of 1.5 percent or two megawatts. The Commission
defined intermittent resources for this purpose as ``an electric
generator that is not dispatchable and cannot store its fuel source and
therefore cannot respond to changes in system demand or respond to
transmission security constraints.'' The Commission also determined
that all generators should be excused from imbalance penalties that
occur due to directed reliability actions by a generator to correct
system frequency.
Requests for Rehearing and Clarification
276. A number of petitioners seek rehearing and/or clarification of
the generator imbalance reforms adopted in Order No. 890. Sempra Global
asks that the Commission revise section 3 of the pro forma OATT to make
clear that generator imbalance service must be offered for any
transmission service used to deliver energy from a generator located
within the transmission provider's control area, as required in
Schedule 9. Sempra Global argues that section 3 of the pro forma OATT
is inconsistent with Schedule 9, since section 3 only requires a
transmission provider to offer generator imbalance service to a
transmission customer serving load within the transmission provider's
control area.
277. EEI, Entergy, and Southern ask that the Commission clarify
that a transmission provider is entitled to charge either the
transmission customer or the generator for generator imbalance service
when the customer takes transmission service to deliver energy to an
off-system load. In their view, generator imbalance charges may only be
assessed to a transmission customer
[[Page 3016]]
under new Schedule 9. Southern and EEI argue that this may be
inappropriate because in many instances the generator is responsible
for the generator imbalance, not the transmission customer. If the
generator sells energy to more than one customer, Southern and EEI
contend that it will be virtually impossible to determine which
transmission customer should be assessed a charge and how the billing
would be determined.
278. EEI and Southern propose changes to Schedule 9 to address
these concerns. EEI asks the Commission to clarify that either the
transmission customer or the generator must take generator imbalance
service in connection with any off-system sale of energy and that the
transmission provider has no obligation to provide transmission service
on its system to an off-system load unless the transmission customer or
the generator executes a service agreement committing to take generator
imbalance service. Southern, however, argues that the Commission should
require every generator, subject to the grandfathering provisions in
Order No. 890, to execute a service agreement to take and pay for
generator imbalance service pursuant to Schedule 9 of the OATT and be a
transmission customer for such purposes. If the Commission does not do
so, Southern asks in the alternative that the Commission clarify that
transmission providers, subject to the grandfathering provisions of
Order No. 890, have no obligation to provide transmission service from
an on-system generator to an off-system load if such generator has not
executed a service agreement under the transmission provider's OATT
providing for the generator to take and pay for generator imbalance
service.
279. PNM argues that transmission providers should not be required
to provide generator imbalance service when doing so would impair
reliability for the transmission provider. PNM contends that some
control area operators may not be able to offer generator imbalance
service unless they can procure balancing energy and associated
capacity from another entity. PNM argues that the obligation to provide
Schedule 9 service should be contingent upon the transmission provider
determining that it is able to provide this service based upon a system
impact study. Even if the service can physically be provided, PNM
states that placing a must-offer requirement in Schedule 9,
particularly for the purpose of supplying imbalance energy for
intermittent generation, may have unreasonable impacts on the supply
resources operated by small host control areas. In PNM's view, an
absolute must-offer requirement for Schedule 9 could lead to
proportionately heavy impacts on small transmission providers that are
required to interconnect generation developed to serve distant urban
areas within large control areas.
280. Joined by EEI and APS, PNM suggests that the Commission
address these reliability concerns by allowing transmission providers
the alternative of offering generators dynamic scheduling to change the
responsibility for generator imbalances from specific generators. In
cases where system reliability would be adversely affected, these
petitioners contend that requiring a generator to accept a dynamic
schedule of its output to the control area where the load is located,
instead of requiring the transmission provider to provide generator
imbalance service, would give the transmission provider a viable
alternative to ensure that the generator's imbalances are absorbed
without compromising the reliability of the system where the generator
is located, while also aligning the responsibility for supplying the
imbalances associated with the parties that enjoy the benefit of the
generation.
281. EEI further argues that imbalance penalties fail to adequately
compensate transmission providers for threats to system reliability
caused by excessive generator imbalances and, therefore, use of dynamic
scheduling would be appropriate. If the Commission does not allow the
alternative of dynamic scheduling, APS requests that the Commission
revise Schedule 9 to allow a transmission provider to identify the
total amount of generator imbalance service it will offer.
282. Other petitioners request clarification or rehearing regarding
the Commission's decision to exempt deviations associated with
correcting system frequency from associated imbalance penalties. Xcel
agrees with the Commission that generators should not be subject to
imbalance penalties that occur when the generator is responding to
reliability directives to correct frequency deviations and requests
that this exception be expressly incorporated into the pro forma OATT.
Xcel requests that the Commission either amend the Order No. 890 pro
forma OATT on rehearing or clarify that a transmission provider can
implement this practice by including such language in its compliance
filing. Xcel suggests that the Commission also could, in the
alternative, clarify that a transmission provider may implement this
practice by posting a business practice indicating the transmission
provider will waive such imbalance charges for generators correcting
frequency deviations on a non-discriminatory basis.
283. EPSA and TAPS request that the Commission expand the exemption
to include other situations in which a generator is directed to be off-
schedule by transmission operators, balancing authorities, or
reliability coordinators. EPSA states, for example, that generators are
often given directives by balancing authorities in order to reduce
unscheduled flows on other systems and/or change line flows or voltage
levels. TAPS argues that there should be an exception for generator
imbalances resulting from transmission loading relief procedures (TLRs)
or other transmission provider instructions, and for both the
unexpected loss of a generating unit and the response of other
generators to replace that unit under the reserve sharing arrangements,
with resulting imbalances treated as being within the first deadband.
TAPS argues that penalizing imbalances in the case of forced generation
outages is particularly inappropriate since such charges do not give
plant operators any better incentive to schedule accurately because
unplanned unit outages by their very nature cannot be predicted and
scheduled.
284. Several petitioners request that the Commission clarify its
definition of intermittent resources for purposes of applying imbalance
charges. TAPS argues that intermittent generation should include test
energy produced by newly completed units, so that generators are not
unduly penalized (i.e., at third-tier penalty levels) for output
variations that are inherently unpredictable. EEI and AMP-Ohio argue
that run-of-river hydroelectric generating facilities should be deemed
to be intermittent resources because their inability to store water to
produce energy on demand satisfies the intention of the Order No. 890
definition, notwithstanding the fact that strictly speaking they do not
have fuel sources. Northwestern, however, argues that run-of-river
hydroelectric projects should not qualify as an intermittent resource
because they generally do have the ability to predict flows and
schedule accurately. NorthWestern also requests that the Commission
specifically require utilities to update their tariffs to reflect this
new definition.
285. AMP-Ohio also argues that intermittent resources should be
entirely exempt from imbalance penalties, arguing that it is unfair to
impose any level of penalties on resources that are not dispatchable.
In AMP-Ohio's view, wind generators and run-of-river hydroelectric
facilities alike depend on uncontrollable forces that
[[Page 3017]]
affect their actual levels of generation. AMP-Ohio argues that fully
exempting intermittent resources from imbalance penalties would not be
unduly discriminatory vis-[agrave]-vis generators that are dispatchable
since the different treatment would merely recognize their different
circumstances.
286. Finally, Entergy asks that the Commission confirm that
transmission providers do not need to seek renewal of existing
generator imbalance agreements. Entergy contends that it is unclear
whether the procedures described in section IV.C of Order No. 890,
regarding Commission consideration of previously-approved variations
from the pro forma OATT, are intended to apply to generator imbalance
agreements that have been previously negotiated between willing
parties.
Commission Determination
287. The Commission affirms the decision in Order No. 890 to adopt
standardized generator imbalance provisions in Schedule 9 of the pro
forma OATT. We agree with Sempra Global that section 3 of the pro forma
OATT, as revised in Order No. 890, does not properly reflect that
generator imbalance service must be offered for any transmission
service used to deliver energy from a generator located within the
transmission provider's control area, as required in Schedule 9. We
revise section 3 to make this clear.
288. We also agree with EEI and Southern that, in certain
circumstances, it may be appropriate for the transmission provider to
allow a generator located within its control area to execute a service
agreement for generator imbalance service, even if the generator is not
otherwise a transmission customer. Without settling with the individual
generator, it could be impossible for the transmission provider to
determine which transmission customer should be assessed a charge and
how the billing would be determined if a single generator was selling
to multiple customers. We have revised Schedule 9 of the pro forma OATT
to require the transmission provider to offer generator imbalance
service to any generator in its control area (subject to the
limitations discussed below). We clarify that, if a generator has
executed a service agreement for generator imbalance service, any
transmission customer scheduling from the generator will be deemed to
have satisfied its obligation to purchase generator imbalance service
under section 3 and Schedule 9.
289. We further clarify that a transmission provider only has to
provide generator imbalance service from its own resources to the
extent that it is physically feasible to do so (i.e., the transmission
provider is able to manage the additional potential imbalances without
compromising reliability). It is not the Commission's intent to require
transmission providers to provide generator imbalance service from its
resources when it would unreasonably impair reliability. Each
transmission provider therefore may state on its OASIS the maximum
amount of generator imbalance service it is able to offer from its
resources, based on an analysis of the physical characteristics of its
system. Alternatively, a transmission provider may consider requests
for generator imbalance service on a case-by-case basis, performing as
necessary a system impact study to determine the precise amount of
additional generation it can accommodate and still reliably respond to
the imbalances that could occur.
290. This does not relieve the transmission provider of its
obligation to provide generator imbalance service if it is able to
acquire additional resources in order to do so. We acknowledge PNM's
concerns that some control area operators may only be able to provide
generator imbalance service by procuring balancing energy and
associated capacity from another entity. If it is not physically
feasible for the transmission provider to offer generator imbalance
service using its own resources, either because they do not exist or
they are fully subscribed, the transmission provider must attempt to
procure alternatives to provide the service, taking appropriate steps
to offer an option that customers can use to satisfy their obligation
to acquire generator imbalance service as a condition of taking
transmission service. In the unlikely circumstance that there are no
additional resources available to enable the transmission provider to
meet its obligation for generator imbalance service, the transmission
provider must accept the use of dynamic scheduling to the extent a
transmission customer has negotiated appropriate arrangements with a
neighboring control area.\103\
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\103\ The Commission addresses request to require transmission
providers to offer dynamic scheduling as a new service under the pro
forma OATT in section III.D.1.d.
---------------------------------------------------------------------------
291. We also reject requests to further exempt intermittent
resources by eliminating imbalance penalties altogether for such
resources. Generator imbalance charges are based on the incremental
costs incurred by the transmission provider to respond to the
generator's imbalance. In the second tier, charges escalate somewhat to
provide an incentive for generators not to deviate outside of the first
tier. Without this penalty component, intermittent resources would not
have any additional incentive to accurately schedule. At the same time,
the Commission recognized that intermittent generators cannot always
accurately follow their schedules and therefore exempted those
resources from third-tier penalties. If given proper incentives,
intermittent generators can improve their forecasting methods in order
to submit more accurate schedules. Thus, we continue to believe this
relaxed penalty structure strikes the right balance between the need to
encourage accurate scheduling and the operating limitations of
intermittent resources.
292. We agree with EEI and AMP-Ohio that the definition of
intermittent resources includes run-of-river hydroelectric units that
do not store water used to generate electricity, i.e., for which
instantaneous inflow equals instantaneous outflow. Hydroelectric units
using storage, however, are not intermittent resources within the
meaning of Schedule 9 of the pro forma OATT. The ability of those units
to schedule their output is not as limited as intermittent resources.
The same is true of newly completed generating units producing test
energy. Under the pro forma OATT, generators do not have to submit
final schedules until the morning of the prior operating day and may
revise those schedules up until 20 minutes prior to the operating hour.
We conclude that this provides sufficient flexibility for hydroelectric
units using storage and newly completed units producing test energy to
change their schedules to reflect forecasted output and that any
charges resulting from remaining imbalances are just and reasonable
under the reformed generator imbalance provisions of the pro forma
OATT.
293. We agree with Xcel that the exemption from generation
imbalance penalties for generators responding to correct frequency
decay should be expressly stated in the pro forma OATT. We also agree
with EPSA and TAPS that a generator that deviates from its schedule due
to directives by balancing authorities, transmission operators, and
reliability coordinators should not be subject to the penalty component
of imbalance charges and that this exemption should be expressly stated
in Schedule 9. It would be inappropriate to assess imbalance penalties
on generators following instructions to, for example, reduce
unscheduled flows on other
[[Page 3018]]
systems (such as a TLR) or change line flows or voltage levels, because
such charges could create incentives not to respond and in turn
compromise reliability. Similarly, generators responding to a reserve
sharing event, with properly structured arrangements with transmission
providers, should not be subject to penalties. We revise Schedule 9
accordingly.
294. We decline, however, to carve out an exception for imbalances
associated with the loss of a generating unit itself. We disagree with
TAPS that penalizing imbalances in the case of forced generation
outages does not give plant operators any better incentive to schedule
accurately. Appropriately designed penalties provide a proper incentive
for generators to reduce instances of forced outage by, for example,
properly maintaining their facilities, and therefore adhere to their
schedules.
295. Finally, we reiterate in response to Entergy that the
Commission did not intend to abrogate existing generator imbalance
agreements as a part of this rulemaking proceeding.\104\ The imbalance-
related reforms do, however, apply to provisions contained in a
transmission provider's OATT, including previously-approved variations
from the pro forma OATT. Transmission providers were given an
opportunity to seek continued approval of such previously-approved
variations, provided the variations continued to be consistent with or
superior to the revised pro forma OATT. We note that Entergy made such
a showing with respect to the generator imbalance provisions of its
OATT.\105\
---------------------------------------------------------------------------
\104\ See Order No. 890 at P 671.
\105\ See Entergy Services, Inc., 120 FERC ] 61,042 (2007).
---------------------------------------------------------------------------
c. Intentional Deviations and Intra-hour Netting
296. The Commission declined in Order No. 890 to impose generic
penalties in the pro forma OATT for intentional deviations, concluding
that the tiered imbalance penalties generally provide a sufficient
incentive not to engage in such behavior. The Commission explained that
proposals to assess additional penalties for intentional deviations
would continue to be considered on a case-by-case basis, subject to a
showing that they are necessary under the circumstances. Any such
tariff provisions must include clearly defined processes for
identifying intentional deviations and the associated penalties.
Requests for Rehearing and Clarification
297. South Carolina E&G argues that the Commission should grant
rehearing to assess additional penalties for entities that deliberately
lean on the system or, in the alternative, provide for generator
imbalance settlements over a shorter period than one hour. In its view,
generators unable to ramp up precisely to meet their schedules can
under-generate in the initial part of the hour and then over-generate
in later parts of the hour in order to integrate closer to the schedule
when settled over the entire hour. South Carolina E&G contends that
this practice imposes costs on balancing authorities and affects system
reliability, yet does not necessarily trigger the higher-tiered
imbalance charges. South Carolina E&G argues that adopting higher
penalties for substantial hourly imbalances does not address the issue
of intra-hour swings, which instead could be resolved by adopting 10-
minute imbalance charges.
Commission Determination
298. The Commission denies rehearing of the decision in Order No.
890 not to impose generic penalties for intentional deviations. We
continue to believe that it is appropriate to maintain the status quo
of aggregating net generation over the hour in the pro forma OATT. To
the extent a transmission provider wishes to adopt additional penalties
for intentional deviations, it may do so provided it can show they are
necessary under the circumstances. As the Commission explained in Order
No. 890, requests to adopt a shorter interval over which to calculate
imbalances also will be considered on a case-by-case basis, provided
that such proposals are consistent with relevant market
structures.\106\
---------------------------------------------------------------------------
\106\ See Order No. 890 at P 722.
---------------------------------------------------------------------------
d. Definition of Incremental Cost
299. In Order No. 890, the Commission defined incremental cost, for
purposes of the tiered imbalance provisions, as the transmission
provider's actual average hourly cost of the last 10 MW dispatched to
supply the transmission provider's native load, based on the
replacement cost of fuel, unit heat rates, start-up costs, incremental
operation and maintenance costs, purchased and interchange power costs
and taxes, as applicable. The Commission also concluded that it was
appropriate, through the definition of incremental cost, to allow for
recovery of both commitment and redispatch costs, but excluded on a
generic basis the cost of additional regulation reserves. The
Commission emphasized that allowable costs should only be those
additional costs incurred by the transmission provider due to the
imbalance and, if applicable, start-up costs should be allocated pro
rata to the offending transmission customers based on cost causation
principles.
300. If the transmission provider elects to have separate demand
charges to recover the cost of holding additional regulation reserves
for meeting imbalances, the Commission stated that the transmission
provider should file a rate schedule and demonstrate that these charges
do not allow for double recovery of such costs. With regard to the
real-time regulation burden imposed by merchant generation, the
Commission stated that transmission providers could propose, on a case-
by-case basis, separate regulation charges for generation resources
selling out of the control area. The Commission concluded that the
other demand costs of providing imbalance service are already provided
under Schedule 3, 5, and 6 charges.
Requests for Rehearing and Clarification
301. While generally supporting the Commission's definition of
incremental costs, Williams requests that the Commission further
identify how each component of the transmission provider's incremental
cost is to be determined. In Williams's view, a specific calculation
methodology should be imposed, otherwise the definition of the
incremental cost will afford transmission providers undue discretion in
the calculation of imbalance charges. To remove this discretion,
Williams suggests that the Commission require transmission providers to
use the same components and the same methodology for the calculation of
incremental costs for imbalance charges as the transmission provider
(or its affiliate) uses to calculate the incremental cost of each
resource for dispatching generation resources. At a minimum, Williams
asks that the Commission require transmission providers to post on
their OASIS the method used to calculate incremental costs for purposes
of imbalance charges, along with the method to obtain each component or
variable in the calculation.
302. Several petitioners argue that the Commission's definition of
incremental cost for purposes of calculating imbalance charges does not
properly account for the costs actually incurred to provide imbalance
energy.\107\ Ameren and Southern assert that failure to provide for
recovery of opportunity
[[Page 3019]]
costs will prevent utilities required to serve an imbalance from being
made whole for forgone opportunities to sell excess energy to third
parties. Ameren contends that the Commission has determined that not
allowing the recovery of opportunity costs is inappropriate when the
applicable rate is lower than the market clearing price.\108\ Ameren
argues that excluding opportunity costs unnecessarily harms the
transmission provider's native load customers since the revenues that
the utilities would have realized from selling their excess energy
would have been credited back to those customers. Southern and E.ON
U.S. ask that the Commission expressly provide that incremental costs
include opportunity costs, as well as environmental costs, capacity
charges, dispatch losses and other costs that the transmission provider
must bear to provide the transmission customer with imbalance service.
---------------------------------------------------------------------------
\107\ E.g., Ameren, EEI, E.ON U.S., and Southern.
\108\ Citing Xcel Energy Services, Inc., 117 FERC ] 61,127
(2006).
---------------------------------------------------------------------------
303. Some petitioners argue that it is inappropriate to base the
calculation of incremental cost on the last 10 MW dispatched to supply
the transmission provider's native load.\109\ EEI argues that the
definition of incremental and decremental cost should be determined
based on the cost to provide the last 10 MW of energy to serve the
transmission provider's native load and all other contractual or
franchise obligations, including the imbalance service itself. Progress
Energy and EEI contend that the transmission provider almost always
incurs incremental costs per kWh that are higher than the incremental
costs of serving its native load because native load typically has
first call on least-cost resources. As a result, EEI argues that the
Commission's definition of incremental cost transfers to imbalance
customers the value of the difference between the incremental cost per
kWh to serve native load and the incremental cost per kWh to serve
other contractual commitments, to the detriment of either the
transmission provider or its native load customers.
---------------------------------------------------------------------------
\109\ See, e.g., Ameren, EEI, MidAmerican, Progress Energy, and
Southern.
---------------------------------------------------------------------------
304. MidAmerican argues that the Commission's definition of
incremental cost could create an incentive to deliberately under-
generate in order to receive the benefit of the transmission provider's
least-cost dispatching. To provide appropriate incentives, Progress
Energy asks that the Commission revise the definition to include the
cost of providing the last 10 MW of energy to serve the transmission
provider's native load plus third party sales, while MidAmerican argues
that imbalance charges should be based on the incremental cost of the
most expensive 10 MW of generation resources in service at the time the
imbalance occurs. Southern contends that incremental cost should be
defined based on the next (not the last) 10 MW dispatched. Southern
asserts that this distinction is especially important in those
instances where the cost of the next 10 MW will be significantly
different than the last 10 MW, such as at the break point requiring
deployment of a combustion turbine generator. Southern therefore asks
that the Commission grant rehearing to establish separate definitions
for incremental and decremental cost and revise the definition of
incremental cost so that it is based on the next 10 MW dispatched.
305. EEI and Progress Energy also seek clarification of the
definition of, and cost recovery for, decremental costs in particular.
EEI contends that the definition adopted in Order No. 890 could result
in the transmission provider crediting the customer an amount that
exceeds the costs that the transmission provider actually avoided by
accepting excess energy. EEI states, for example, that a transmission
provider might decrease the output of a dispatchable unit in response
to an imbalance even though it might also have a higher-cost power
purchase contract with a fixed amount of energy to be delivered in that
hour. EEI argues that the Commission's definition of decremental cost
would require the transmission provider to pay the imbalance customer
based on the higher-cost purchased power resource even though it has
not avoided those costs as a result of accepting the customer's excess
energy. In EEI's view, decremental cost should be defined to include
costs that are avoided as a result of receiving imbalance energy.
306. Progress Energy asks that the definition of decremental cost
be clarified to allow the recovery of start-up costs that are incurred
in an hour different from the hour of excess imbalance. Progress Energy
contends that requiring a transmission provider to accept excessive
imbalance energy could force it to cycle a unit off-line in order to
accommodate the energy. Progress Energy argues that the later start-up
cost for the shut-down unit should be passed along to the imbalance
customer, rather than shifted to the native load.
307. Other entities assert the Commission's definition of
incremental cost is inappropriate in light of their particular market
structure. When a joint dispatch agreement exists between the
transmission provider and other balancing authorities, MidAmerican
argues that the joint dispatch incremental or decremental cost should
be used in place of native load since there is no identification of the
transmission provider's native load other than as part of an
aggregated, jointly dispatched load. MidAmerican also argues that
transmission providers may have little or no native load from which to
price imbalance costs in retail choice states. NorthWestern agrees that
the definition of incremental cost fails to consider the circumstances
of transmission providers that have little or no generation on their
system. NorthWestern argues that the Commission should have expressly
provided additional flexibility for such transmission providers through
the definition of incremental cost instead of requiring them to file
under FPA section 205 for acceptance of previously-approved imbalance
pricing based on purchased power costs.
308. Entergy challenges as too narrow the Commission's decision to
consider on a case-by-case basis proposals to charge separate
regulation charges for generation resources selling out of the control
area. Entergy states that the generator imbalance provisions of its
OATT contain both a generator imbalance charge and a generator
regulation charge, each of which are calculated based on the internal
and external schedules submitted by independent generators. Entergy
argues that this is appropriate because, regardless of whether the load
is within the control area or outside the control area, the generator
has a schedule with the control area that is met by control area
resources. Entergy contends that applying a generation regulation
charge only to external transactions would be arbitrary. Entergy
requests clarification that the generator regulation service charges
contained in its pro forma Generator Imbalance Agreement, which Entergy
states was negotiated with generators on its system, continues to be
acceptable.
Commission Determination
309. The Commission grants rehearing of the decision to calculate
incremental costs for purposes of assessing imbalance charges based on
the last 10 MW dispatched to supply the transmission provider's native
load. Upon consideration of petitioners' arguments, we agree that it is
more reasonable to base imbalance charges on the actual cost to correct
the imbalance, which may be different than the cost of serving native
load. As such, we will
[[Page 3020]]
modify the definition to require transmission providers to use the cost
of the last 10 MWs dispatched for any purpose, i.e., to serve native
load, correct imbalances, or to make off-system sales. We believe this
satisfies Southern's concerns and therefore decline to adopt its
suggestion to separately define incremental and decremental cost for
purposes of calculating imbalance charges by using the ``next 10 MW of
generation dispatched'' in the incremental cost definition.
310. We also agree with Williams that, in order to provide
transparency and minimize opportunities for undue discrimination, each
transmission provider must provide language in its OATT clearly
specifying the method by which it calculates incremental costs for
purposes of imbalance charges, as well as the method it will use to
obtain each component of the calculation. We direct transmission
providers to include this proposed tariff language as part of the
compliance filing ordered in section II.C.
311. Several entities complain that the Commission's definition of
incremental cost does not properly allow for recovery of opportunity
costs. The determination and calculation of opportunity costs
associated with providing imbalance service will vary based on the
circumstances of the transmission provider and, as such, we do not
believe that it is appropriate to amend the definition of incremental
cost in the pro forma OATT to address opportunity costs. We will
therefore continue to consider proposals to include recovery of
legitimate and verifiable opportunity costs on a case-by-case basis
consistent with Commission precedent.\110\ Such proposals must clearly
explain how opportunity costs would be determined and demonstrate that
the recovery of opportunity costs would not lead to over-recovery of
costs. Similarly, transmission providers participating in joint
dispatch agreements or otherwise procuring imbalance energy from other
generators may need to have alternative definitions of incremental
cost. Proposals to adopt a modified definition of incremental cost to
reflect the transmission provider's particular circumstances also will
be considered on a case-by-case basis.
---------------------------------------------------------------------------
\110\ See Order No. 888 at 31,740.
---------------------------------------------------------------------------
312. With regard to the definition of incremental cost in
particular, we clarify that transmission providers can include in the
calculation of incremental cost start-up costs that are incurred in an
hour different from the hour of excess imbalance, provided that the
costs are in fact associated with providing imbalance service. We
disagree with EEI with respect to its description of incremental costs.
The fixed amount power purchase contract in EEI's example should not be
used in calculating incremental costs because it would not be included
in the last 10 MW of generation dispatched by the transmission
provider. In the case that a transmission provider is ramping down
generation in an hour, the additional costs of the last 10 MW
dispatched by the transmission provider should be used in calculating
incremental costs for the purpose of financially settling imbalances.
313. In response to Entergy, we clarify that transmission providers
may propose to assess regulation charges to generators selling in the
control area, as well as generators selling outside the control area,
and that the Commission will consider such proposals on a case-by-case
basis, as we have in the case of Entergy's pro forma Generator
Imbalance Agreement. In accordance with the procedures established in
Order No. 890, Entergy sought continued approval of its generator
imbalance provisions, including the assessment of generator regulation
charges. The Commission accepted this variation as consistent with or
superior to the pro forma OATT, based on the particular circumstances
presented by Entergy.\111\ We will continue to consider requests to
assess regulation charges on generators on a case-by-case basis upon
consideration of the facts and circumstances presented.
---------------------------------------------------------------------------
\111\ See Entergy Services, Inc., 120 FERC ] 61,042 at P 66
(2007).
---------------------------------------------------------------------------
e. Inadvertent Energy Treatment
314. The Commission found in Order No. 890 that inadvertent energy
is not comparable to energy and generator imbalances and, therefore,
allowed inadvertent energy to be treated differently from imbalances.
The Commission explained that variables affecting inadvertent
interchange often depend on the actions or the omissions of utilities
other than the individual transmission providers and are distinct from
those resulting in energy and generator imbalances. The Commission
concluded that the historic practice of paying back inadvertent
interchange in kind has not proven to have adverse effects on
reliability.
Requests for Rehearing and Clarification
315. TDU Systems contend that the Commission's acceptance of in-
kind compensation for interchange energy undermines its rejection of
requests to allow transmission customers to address monthly imbalances
with in-kind transfers. TDU Systems argue that there is no evidentiary
basis for the Commission to conclude that transmission providers have
little control over the causes of system imbalances. TDU Systems state
that transmission providers typically control 80-90 percent of the load
on their systems and the dispatch of resources to serve that load. In
TDU Systems' view, both transmission provider and transmission customer
imbalances result from circumstances beyond their control, namely:
telemetry failure, meter error, generator governor response to system
problems, human error, uncontrollable load forecast errors due to
rapidly changing weather, and under-or over-supply of generation.
316. TDU Systems state that deviations between load and supply,
whether in the form of energy imbalances or inadvertent energy, each
require adjustment or compensation and that there is no reason why that
adjustment or compensation should be different among transmission
users. TDU Systems argue that failure to allow for in-kind payment for
imbalances within the month provides a competitive advantage to
transmission providers and constitutes undue discrimination in
violation of the FPA. In their view, the Commission remedied this
discrimination within RTOs by requiring in Order No. 2000 that the same
imbalance rules apply to transmission users and control area
operators.\112\ TDU Systems argues that the Commission fails to explain
its departure from its resolution of this issue in the RTO context and
that it is irrelevant that transmission providers may have historically
paid back inadvertent interchanges with in-kind transfers without
problem.
---------------------------------------------------------------------------
\112\ Citing Regional Transmission Organizations, Order No.
2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. & Regs. ] 31,089 at
31,142 (1999), order on reh'g, Order No. 2000-A, 65 FR 12088 (Mar.
8, 2000), FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Public
Utility District No. 1 of Snohomish County, Washington v. FERC, 272
F.3d 607 (D.C. Cir. 2001).
---------------------------------------------------------------------------
Commission Determination
317. The Commission denies rehearing of the decision in Order No.
890 to allow inadvertent energy to be treated differently from energy
and generator imbalances. As the Commission explained in Order No. 890,
inadvertent energy is not comparable to energy and generation
imbalances and the variables affecting each are distinct. It is
therefore
[[Page 3021]]
appropriate to treat inadvertent energy and imbalances differently
notwithstanding the fact that both inadvertent exchanges and imbalances
may be beyond the control of the transmission provider or customer,
respectively.
318. Our primary concern with respect to inadvertent energy
continues to be avoidance of incentives that could degrade reliability.
To date, the return-in-kind approach to inadvertent energy has proven
adequate as a general matter. Petitioners do not present any evidence
that in-kind payment of inadvertent energy is no longer sufficient to
maintain reliability or allows certain entities to lean on the grid to
the detriment of other entities. We disagree that this treatment of
inadvertent energy is inconsistent with Order No. 2000. There the
Commission required both control area operators and transmission
customers within an RTO to clear imbalances through a real-time
balancing market.\113\ In the absence of a real-time balancing market,
we continue to believe it is appropriate for transmission providers
operating under the pro forma OATT to treat inadvertent interchange
differently than customer imbalances.
---------------------------------------------------------------------------
\113\ See Order No. 2000 at 31,142.
---------------------------------------------------------------------------
f. Netting of Energy and Generator Imbalances
319. In Order No. 890, the Commission concluded that it is not
appropriate to require transmission providers to allow netting of
generator and energy imbalances outside of the tier one band. While the
Commission recognized that allowing transmission customers to net
energy and generator imbalances would have competitive benefits and
enhance comparability, the Commission determined that it could lessen
the incentive for accurate scheduling and, in turn, increase imbalances
that create reliability or economic issues for specific areas of the
system.
Requests for Rehearing and Clarification
320. Several petitioners ask that the Commission clarify that
netting and settling within the first deviation band should be done on
a financial basis, based on hourly incremental and decremental costs,
rather than netting imbalances on the basis of megawatt-hours of
imbalance and settling the net imbalance on a financial basis.\114\
EEI, MidAmerican and Progress Energy assert that otherwise customers
would be able to offset energy shortfalls in on-peak, high-cost periods
against excess energy in off-peak, lower-cost hours, which would
inappropriately shift costs to native load customers. If imbalances are
netted based on megawatt-hours prior to financial settlement, EEI and
Progress Energy argue that it would be impossible to calculate charges
for net imbalances at the end of the month because the transmission
provider would not be able to correlate monthly net imbalances with
hourly incremental and decremental costs without exercising subjective
judgment. Southern and EEI contend that the Commission, at a minimum,
should require the imbalances to be netted separately for on-peak
periods and off-peak periods if it determines that imbalances should be
netted on a megawatt-hour basis. EEI suggests that the price for net
first tier imbalances then be based on each month's average incremental
and decremental costs, calculated separately for on-peak periods and
off-peak periods.
---------------------------------------------------------------------------
\114\ E.g., EEI, MidAmerican, Southern, Progress Energy, and
Entergy.
---------------------------------------------------------------------------
321. Other petitioners assert that the Commission should allow
netting outside of the first tier band.\115\ Ameren argues that the
threshold of the first tier band is unnecessarily low, suggesting it
would be more appropriate to allow imbalances of less than 10 MW to be
netted. For imbalances from 10 MW up to as much as 50 MW, Ameren
suggests that the Commission allow netting of imbalances equal to the
greater of 10 MW or 50 percent of its scheduled amount. TDU Systems
argue that transmission customers should be allowed to net all
imbalances across the transmission system within a month, reflecting
appropriate differences for imbalances incurred during peak and off-
peak hours. TDU Systems contend that netting should be unrestricted
within the month so long as the results keep the transmission provider
economically whole. TDU Systems argue that there is no evidence that
netting creates reliability problems and that limiting netting is not
comparable to the transmission provider's treatment of imbalances of
its retail native load, generation affiliates, and marketing
affiliates. TDU Systems also argue that restricting netting within the
month is an unexplained departure from the Commission's treatment of
natural gas pipeline imbalances.
---------------------------------------------------------------------------
\115\ E.g., TAPS, Ameren, and TDU Systems.
---------------------------------------------------------------------------
322. NRECA asks the Commission to confirm, either on clarification
or rehearing, that separate imbalance charges may not be assessed on
each of a customer's separate transactions on an interface or within a
control area in a single hour. NRECA contends that a customer's
contribution to area control error (ACE) on a given interface is no
more than the aggregate difference between schedules and deliveries
and, therefore, its impact on the balance of resources and loads within
a control area is no more than the aggregate difference between its
resources' output and its load. If a transmission provider's system is
so underdeveloped that constraints prevent transactions sourcing at
different locations within the control area from being treated
comparably, the Commission should require the transmission provider to
upgrade its system rather than penalize the customer with multiple sets
of imbalance charges on separate transactions.
Commission Determination
323. The Commission affirms the decision in Order No. 890 to allow
netting of imbalances within the first tier deviation band. As the
Commission explained in Order No. 890, there is a tradeoff between
allowing customers to net imbalances, which would enhance comparability
between the transmission provider's dispatch and the customers serving
load, and the need to create incentives to limit customer imbalances
due to the reliability or economic issues they can cause for specific
areas of the system.\116\ Netting can cause problems because it lessens
the incentive for transmission customers to schedule accurately and
inaccurate schedules, in turn, can require actions by the transmission
provider even when imbalances offset. We believe the Commission struck
the appropriate balance in Order No. 890 between the customer's need
for flexibility and the transmission provider's need for accuracy and,
therefore, deny TDU Systems' request to require netting of imbalances
outside the tier one band and Ameren's related request to expand the
tier one band for purposes of netting.
---------------------------------------------------------------------------
\116\ See Order No. 890 at P 715.
---------------------------------------------------------------------------
324. We also deny NRECA's request that separate imbalance charges
not be assessed on each of a customer's separate transactions on an
interface or within a control area in a single hour. Where transmission
constraints exist, a customer whose load and generation was on net
equal could still have an effect on the transmission system if some
generation is ramping up to respond to some imbalances while other
generation is ramping down exactly at the same time. We disagree with
TDU Systems that our decision is an unexplained departure from the
Commission's treatment of natural gas
[[Page 3022]]
pipeline imbalances. Natural gas pipelines frequently have
opportunities to use storage and line pack to absorb day-to-day
imbalances. Individual pipelines have tailored their imbalance
requirements, including penalty provisions as needed, to meet their
specific circumstances. The transmission of electricity, in contrast to
the transportation of natural gas, requires instantaneous balancing
which makes the need for imbalance provisions on a shorter-term basis
important for the protection of reliability. NERC has created standards
such that each control area is responsible for managing its Area
Control Error and operating within line limits in order to protect
reliability. Imbalances created by transmission customers impose an
additional burden on the transmission provider to manage imbalances
within the hour (as well as shorter time periods) justifying a
different tariff approach under the pro forma OATT. As such, the
imbalances provisions adopted in the pro forma OATT are used to protect
reliability during the applicable time period.
325. With regard to netting within the tier one band, we clarify
that netting should be done on a megawatt-hour basis, rolling over the
month. Imbalances remaining at the end of the month should be settled
at the load weighted average of the hourly incremental costs during
that month.\117\ We decline to require that imbalances be netted
separately for on-peak and off-peak periods. Netting only applies to
imbalances within the tier one band, which are relatively minor and
largely within the normal range of uncertainty that cannot be avoided
even under optimal operating conditions. We therefore disagree that it
is necessary to adopt a more granular imbalance pricing mechanism when
netting imbalances within the first tier. However, if a transmission
provider finds that its customers are arbitraging on-peak and off-peak
prices within the first tier, it may propose a more granular approach
to netting subject to a showing that it is necessary under the
circumstances.
---------------------------------------------------------------------------
\117\ For example, if a generator had 5 imbalances within the
first deviation band in a month of +2 MWh, -6 MWh, +4 MWh, -2 MWh, -
1 MWh, the net MWh imbalance for the generator at the end of the
month would be -3 MWh. The generator would pay the transmission
provider for 3 MWh at the load weighted average of the hourly
incremental costs during that month.
---------------------------------------------------------------------------
g. Distribution of Penalty Revenues Above Incremental Cost
326. With regard to revenues received through imbalance charges,
the Commission required transmission providers to develop a mechanism
for crediting such revenues to all non-offending transmission
customers, including affiliated transmission customers, and the
transmission provider on behalf of its own customers. The Commission
concluded that such distribution of revenues recognizes that
transmission providers bear the responsibility to correct imbalances
and often use their own facilities to do so.
Requests for Rehearing and Clarification
327. Ameren contends that the transmission provider should be
allowed to keep all the penalty revenues associated with correcting
imbalances and that development of a credit mechanism imposes an
unnecessary and unwarranted administrative burden on transmission
providers. Ameren argues that the transmission provider should receive
any amounts above its incremental costs of providing imbalance service
as a contribution towards the fixed costs of providing this service and
that any revenues from penalties assessed on customers for leaning on
the system should be credited to long-term firm transmission customers.
328. TDU Systems, however, object to the Commission's decision to
allow transmission providers to retain a portion of the imbalance
penalty revenues for their own retail customers. TDU Systems contend
that transmission providers do not pay imbalance penalties when they
over- or under-schedule their loads and, thus, receipt of related
penalty revenues by transmission providers would constitute a windfall.
TDU Systems argue that the Commission failed to explain its departure
from Carolina Power & Light \118\ because the Commission's decision in
that case to deny credits to CP&L on behalf of its retail customers was
based on those customers not being subject to energy imbalance
penalties in the first place. TDU Systems contend that this fundamental
paradigm has not changed with reform of the OATT.
---------------------------------------------------------------------------
\118\ 103 FERC ] 61,209 (2003) (CP&L).
---------------------------------------------------------------------------
329. MidAmerican requests clarification that it is appropriate to
propose its imbalance penalty distribution mechanism in the compliance
filing containing the non-rate terms and conditions of the pro forma
OATT. Joined by NorthWestern and Mark Lively, MidAmerican also requests
guidance as to the particular information the Commission would require
in those filings with regard to the penalty distribution mechanism.
NorthWestern asks the Commission to specify how the transmission
provider should determine what customers are non-offending and over
what period of time. Mark Lively seeks clarification of the time frame
during which there is to be a matching of penalty revenue and credits
to non-offending customers. If the matching is done on a monthly basis,
Mark Lively contends that most if not all transmission customers will
be found to be offending at some time during the month and thus not be
eligible to be in the class of customers to receive a credit for part
of the penalty revenue collected by the transmission provider. Mark
Lively suggests an alternative crediting mechanism to synchronize
penalties and credits by having the variance from full incremental cost
be uniform for any hour or any intra-hour period, with revenues from
over-deliveries shared with non-offending load and revenues from under-
deliveries shared with non-offending supply.
330. NorthWestern also asks the Commission to expressly confirm
that the transmission provider is not required to distribute penalty
revenues until after it recovers all costs (including any associated
transmission costs) incurred in providing imbalance service.
NorthWestern contends that the market for such services is limited and,
as a result, it has had to contract with entities located outside its
control area for system balancing and load following services in order
to provide imbalance service.
Commission Determination
331. The Commission affirms the decision in Order No. 890 to
require transmission providers to credit revenues from imbalance
charges in excess of incremental costs to all non-offending customers,
including affiliates, and the transmission provider on behalf of its
retail customers. As the Commission explained in Order No. 890,
transmission providers with significant imbalance penalties have been
required in the past to develop a mechanism to credit penalty revenues
to non-offending transmission customers.\119\ We disagree with Ameren
that this imposes an unreasonable administrative burden on transmission
providers. We note that Ameren did not seek rehearing of the decision
to require transmission providers to develop a similar mechanism to
distribute unreserved use penalties to non-offending customers,
discussed in section III.C.4.b.\120\ We would not
[[Page 3023]]
expect development of that distribution mechanism to be any more
burdensome than distributions of imbalance penalty revenues.
---------------------------------------------------------------------------
\119\ See Order No. 890 at P 727 (citing CP&L, 103 FERC ] 61,209
at P 25; Entergy Services, Inc., 105 FERC ] 61,319 (2003), reh'g
denied, 109 FERC ] 61,095 (2004)).
\120\ See id. at P 860-61.
---------------------------------------------------------------------------
332. We also disagree with TDU Systems that the transmission
provider on behalf of its native load customers should be excluded from
the distribution of imbalance revenues. Transmission providers bear the
responsibility to correct imbalances, often using their own facilities
to do so, and thus their receipt of imbalance revenues does not
constitute a windfall. While it is true that the Commission in CP&L
considered relevant the fact that CP&L's customers were not subject to
imbalance charges, the Commission expressly rejected CP&L's proposal to
retain revenues because it would have been ``contrary to the
Commission's objective to eliminate incentives for transmission
providers to use penalties as a profit center.'' \121\ The imbalance
charges adopted in Order No. 890 more closely relate to incremental
cost and therefore minimize any incentive on the part of the
transmission provider to rely on penalty revenues rather than seeking
other methods of encouraging accurate scheduling. Under these
circumstances, there remains no reason to exclude the transmission
provider from receiving an appropriate share of penalty revenues.
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\121\ CP&L, 103 FERC ] 61,209 at P 26.
---------------------------------------------------------------------------
333. Regarding the time frame during which there is to be a
matching of penalty revenue and credits to non-offending customers, we
clarify that the transmission provider should distribute the penalty
revenue received in a given hour to those non-offending customers in
that hour, i.e., those customers to whom the penalty component did not
apply in the hour. Customers that were out of balance, but within the
first tier, should therefore be included in the distribution. Since
most transmission customers will be out of the first deviation band at
some hour during the month, we agree that it would not be appropriate
to exclude these customers from receiving a pro rata portion of penalty
revenues in the other hours. In response to NorthWestern, we clarify
that the transmission provider, as part of its distribution
methodology, may address how distributions may be affected by the
transmission provider's inability to recover the costs incurred to
provide imbalance service.
2. Credits for Network Customers
a. Severance of Credits and Planning
334. In Order No. 890, the Commission adopted the NOPR proposal to
sever the link in the pro forma OATT between joint planning and credits
for new facilities owned by network customers. The Commission concluded
that linking credits for new facilities to a joint planning requirement
can act as a disincentive to coordinated planning, which is contrary to
the Commission's original objective in adopting the provision. The
Commission also concluded that the coordinated planning initiatives
adopted in Order No. 890 will ensure that most, if not all,
transmission facilities are planned on a coordinated basis,
notwithstanding the severance of the link between credits for new
facilities and joint planning.
Requests for Rehearing and Clarification
335. E.ON U.S. argues on rehearing that the Commission failed to
adequately address comments suggesting that severing the link will
excuse network customers from participating in the joint planning
process and permit a network customer to build facilities without
oversight or input from a transmission provider. While Order No. 890
places an affirmative burden on the transmission provider to coordinate
long-term transmission planning, E.ON U.S. states that no corresponding
obligation is placed on the transmission customer. E.ON U.S. argues
that transmission service credits for facilities constructed by network
customers should be available only when the facility is jointly planned
with the transmission provider.
336. NorthWestern agrees, arguing that if a network customer is
permitted to construct facilities and later declare them to be worthy
of a credit, such facilities will not serve the overall grid as
efficiently as jointly planned facilities. NorthWestern also argues
that severing the link will lead to protracted litigation regarding
what facilities qualify for credits. To ensure efficient coordination
of facility planning, NorthWestern requests that the Commission
reconsider its decision to sever joint planning and transmission
service credits.
Commission Determination
337. E.ON U.S. and NorthWestern both argue that, by severing the
link between joint planning and credits for network customers, the
Commission is sacrificing the benefits that resulted when a
transmission provider made credits available as part of its centralized
planning process. We disagree. As the Commission explained in Order No.
890, the linkage between credits and joint planning gave the
transmission provider an incentive to deny coordinated planning to
avoid granting credits for customer-owned facilities.\122\ Therefore,
it was necessary to sever the link between credits and joint planning.
Any efficiencies that may be lost by severing that link should be
offset by the increased efficiencies resulting from the coordinated
planning initiative required in Order No. 890, which the Commission
noted will ensure that most, if not all, transmission facilities are
planned on a coordinated basis.\123\ With the clarifications provided
below, we do not expect that severing the link between joint planning
and credits will lead to unnecessary litigation.
---------------------------------------------------------------------------
\122\ See Order No. 890 at P 735.
\123\ See id. at P 736.
---------------------------------------------------------------------------
b. The New Test To Determine Eligibility for Credits
338. In Order No. 890, the Commission declined to adopt the credits
test for new facilities proposed in the NOPR and, instead, revised the
test to more accurately reflect the Commission's intent as expressed in
the NOPR. A transmission customer is required to meet the integration
standard under pro forma OATT section 30.9 to receive a credit for its
facilities. Under the integration standard, the customer must
demonstrate that its facilities not only are integrated with the
transmission provider's system, but also provide additional benefits to
the transmission grid in terms of capability and reliability and can be
relied on by the transmission provider for the coordinated operation of
the grid.\124\ Because joint planning will no longer be required to
obtain credits, the Commission noted that it is particularly important
in this context to require a showing that a network customer's
facilities provide benefits to the transmission provider's grid. To
ensure comparability, the Commission adopted the presumption of
integration for transmission customer facilities that, if owned by the
transmission provider, would be eligible for inclusion in the
transmission provider's annual transmission revenue requirement as
specified in Attachment H of the pro forma OATT.
---------------------------------------------------------------------------
\124\ See id. at P 754, n.436 (citing Southwest Power Pool,
Inc., 108 FERC ] 61,078 (2004), reh'g denied, 114 FERC ] 61,028
(2006)).
---------------------------------------------------------------------------
Requests for Rehearing and Clarification
339. NRECA, TAPS and the TDU Systems request that the Commission
confirm that the integration requirement under Order No. 890 does not
require a more stringent standard for network customer facilities than
for transmission provider facilities or in any way
[[Page 3024]]
compromise the language in section 30.9 of the pro forma OATT. NRECA
argues that the language in Paragraph 754 of Order No. 890 and, in
particular the affirmation of the ``benefits to the grid'' test in
footnote 436, contradict section 30.9 by establishing an explicitly
different and harder test for transmission customer facilities than for
transmission provider facilities. Other petitioners agree,\125\
requesting that the Commission explain that it did not intend to impose
the ``additional benefits to the grid'' and ``relied on by the
transmission provider'' criteria (which they state are not required for
a transmission provider's facilities) on a network customer's
facilities.
---------------------------------------------------------------------------
\125\ E.g., TAPS and TDU Systems.
---------------------------------------------------------------------------
340. Several petitioners argue that an integration standard
requiring the showing of benefits to the grid is unduly discriminatory
because it maintains the presumption that a transmission provider's
transmission facilities provide benefits while requiring a network
customer to make an affirmative showing that its facilities provide
benefits to qualify for credits.\126\ FMPA and TDU Systems argue that
comparability requires the same presumption of integration to be
applied to all transmission facilities. To provide certainty for those
building new infrastructure, TDU Systems contend that the Commission
should require transmission providers to credit third parties for the
costs of new facilities in a manner comparable to the compensation
provided for a transmission provider's comparable facilities.
---------------------------------------------------------------------------
\126\ E.g., APPA, FMPA, NRECA and TAPS.
---------------------------------------------------------------------------
341. APPA contends that the presumption of integration is confusing
because it is unclear how a network customer would make a showing that
facilities would be eligible for inclusion in a transmission provider's
revenue requirement if owned by the transmission provider or what the
specific legal effect would be if the network customer succeeded in
making such showing. APPA suggests that the Commission require credits
if the customer can show that the transmission provider includes in its
own revenue requirement or gives credits to other customers for
facilities similar to those for which the networks customer seeks
credits.
342. In implementing the presumption of integration to obtain
credits, TAPS and APPA maintain that the Commission cannot require a
network customer to show more than that its facilities are comparable
to similar facilities the transmission provider actually includes in
its rate base. TAPS argues that the Commission should clarify that the
presumption cannot be overcome by evidence that the transmission
provider and the transmission provider's other customers do not use or
directly benefit from the customer-owned facilities. TAPS therefore
requests that the Commission make clear that it will not follow
precedents developed in credit cases decided under the original OATT
section 30.9 regarding the types of ``benefits'' provided by a
customer's facilities. Specifically, TAPS argues that a network
customer of a transmission provider that includes the cost of
facilities (including radials) that are used solely to serve the
transmission provider's retail customers must be able to use the Order
No. 890's presumption to obtain credits for similar facilities that
serve only that transmission customer's retail customers.
343. FMPA also oppose any implementation of the Commission's
integration test that treats customers and transmission providers
differently. FMPA argue that, if a customer's facilities are necessary
to serve the customer's load, the customer should be provided a credit
since the transmission provider includes in rate base the cost of its
facilities used to serve load. In their view, the same presumption of
integration applies to all transmission facilities, i.e., that
transmission is integrated when, if owned by the transmission provider,
it would be includable in rate base. FMPA cite legislative history and
the court's decision in TAPS v. FERC \127\ in support of their argument
that the comparability principle is central to the issue of cost
recognition for customer facilities. FMPA contend that recognizing
their members' transmission through credits is beneficial because it
involves all owners in joint planning and the exchange of information
that results in grid construction and operation that will better serve
the needs of all consumers. Without this role in joint planning, less
reliable transmission and fewer generation and power supply options for
systems will result. In addition, if credits are denied, FMPA will be
inhibited from contributing necessary capital to the grid and likely
result in reduced public support for transmission construction.
---------------------------------------------------------------------------
\127\ 225 F.3d 667, 681 (D.C. Cir. 2000), aff'd sub nom., New
York v. FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------
344. Other petitioners contend that the Commission should eliminate
any presumption that a network customer is entitled to credits, arguing
that the presumption violates the cost-causation principle by shifting
costs to customers for whom the facilities were not planned and who are
not benefited by their use.\128\ These petitioners contend that a
network customer's facilities are not planned around the needs of the
transmission provider to meet its obligations and many customer
facilities are designed only to pick up power from the transmission
provider's grid and deliver it to that network customer's distribution
network.\129\ These petitioners request that the Commission allow for
credits only when the customer's facilities provide a benefit to the
transmission provider's grid, i.e., when the transmission provider
relies on a network customer's facility to serve the transmission
provider's transmission customers (including the network customer
seeking credits) or the transmission provider's retail customers. They
argue that there is no basis to presume integration simply because the
transmission provider would include the cost of such facilities were it
the owner.
---------------------------------------------------------------------------
\128\ E.g., Entergy and Florida Power.
\129\ E.g., Entergy, Florida Power and South Carolina E&G.
---------------------------------------------------------------------------
345. South Carolina E&G argues a presumption of integration will
encourage customer overbuilding paid for by a transmission provider's
native load customers. South Carolina E&G asks that the Commission
confirm that it is not departing from the decade-old two-part test for
credits for customer-owned facilities that requires that the facilities
are both integrated into the network grid and provide benefits to the
grid. South Carolina E&G disagrees that any revision to that test is
required by comparability. In its view, customer-owned facilities are
not comparable to transmission provider-owned facilities for purposes
of credit eligibility, since each are built for different purposes and
are subject to different regulatory oversight.
346. Florida Power argues that the application of the rebuttable
presumption may impact reliability. Florida Power contends that, under
the new test for credits, a transmission provider must show that it
does not need the network customer's facilities to provide transmission
service to any other customer in order to deny credits. Florida Power
states that this could result in a network customer being denied
credits for a facility even if the transmission provider needs the
facility to reliably serve the network customer.
347. Entergy and Florida Power also request that the Commission
change its policy of applying a stricter standard to a transmission
provider's own facilities
[[Page 3025]]
when a network customer has been denied credits. These petitioners
state that, when the Commission denies credits for customer-owned
facilities, it applies the same integration test to the transmission
provider's facilities as that applied to the network customer's
facilities. The petitioners argue that application of the integration
test to the transmission provider's facilities in that instance is
unreasonable since the nature of those facilities does not change. They
argue that different tests for transmission providers and network
customer systems are appropriate since each are planned for and used
differently. In their view, concerns about comparability can be
addressed by allowing a transmission provider's looped facility to be
rolled into rate base only if the transmission provider uses the
facility to serve a transmission customer or the transmission
customer's retail customers.
348. Entergy and Florida Power further claim that the Commission's
approach is inconsistent with the treatment of generator
interconnections because the Commission's policy entitling an
interconnecting generator to credits against transmission charges does
not change simply because the Commission has denied a network customer
credits. These petitioners contend that an interconnecting generator
could be entitled to credits when at the same time the transmission
provider could be prohibited from rolling the costs of those credits
into its rates.
Commission Determination
349. The Commission denies rehearing of the decision in Order No.
890 to modify the credits test for new customer-owned facilities. In
Order No. 890, the Commission explained that it was retaining the
existing integration standard, but adopting a new presumption of
integration for customer-owned facilities that would be included in
rate base if owned by the transmission provider.\130\ The integration
standard to be applied to new facilities under section 30.9 therefore
remains unchanged, so Commission precedent regarding application of the
standard will continue to apply. Specifically, to satisfy the
integration standard set forth in section 30.9 of the pro forma OATT,
it must be shown that a new facility is integrated with a transmission
provider's system, provides additional benefits to the transmission
grid in terms of capability and reliability, and can be relied on by
the transmission provider for the coordinated operation of the
grid.\131\ However, in recognition of the new requirement for
transmission providers to plan their system on an open and coordinated
basis, a customer's transmission facilities will be presumed to be
integrated if the facilities, if owned by the transmission provider,
would be eligible for inclusion in the transmission provider's annual
transmission revenue requirement as specified in Attachment H of the
pro forma OATT.
---------------------------------------------------------------------------
\130\ Order No. 890 at P 753-754.
\131\ Southwest Power Pool, Inc., 108 FERC ] 61,078 at P 17
(2004) (citing Order No. 888-A at 30,271), reh'g denied, 114 FERC ]
61,028 (2006).
---------------------------------------------------------------------------
350. The adoption of this presumption is necessary to ensure
comparability between network customers and transmission providers
serving native load. It is reasonable to presume, without application
of any particular standard or test, that the transmission provider's
facilities benefit the network because they are planned, constructed
and owned, from the beginning, by the transmission provider to meet its
obligations to its customers. In comparison, because customer-owned
facilities are generally constructed to serve that individual
customer's needs, the Commission requires the customer to satisfy the
integration standard in order to qualify for credits. The Commission
concluded in Order No. 890 that it is now reasonable to presume that
any new customer-owned facilities satisfy the integration standard, to
the extent they would be included in the transmission provider's
revenue requirement if they were owned by the transmission provider, in
light of the requirement imposed on transmission providers to implement
an open and coordinated transmission planning process that applies to
all transmission facilities.
351. To the extent necessary, we clarify that these presumptions of
integration are rebuttable both as applied to the transmission provider
and the network customer. For the network customers' facilities,
transmission providers may challenge the presumption that the
customer's facilities are integrated by showing they do not actually
meet the integration standard, notwithstanding the fact that they are
similar to facilities in the transmission provider's rate base.
Similarly, the presumption that a transmission provider's facilities
benefit the network could be overcome by a showing that the facilities,
in fact, do not provide such benefit. By allowing the presumptions of
integration to be rebutted, the Commission will ensure that only the
costs of facilities that are actually part of the integrated network
that serves all customers will receive credits. It also serves as an
incentive for the transmission provider to give credits to network
customers that own integrated facilities and remove from its rate base
its own non-integrated facilities.
352. In light of the modifications to the credits test adopted in
Order No. 890, we further clarify that denial of credits for a network
customer no longer triggers a need for the transmission provider to
demonstrate that its own facilities satisfy the integration standard,
because credits for network customer facilities can now be denied only
after an affirmative showing by the transmission provider that its
facilities are not similar under the integration test to those of the
network customer (i.e., by overcoming the presumption of integration).
This approach departs from the approach adopted in FP&L,\132\ but
reflects the fact that the new rebuttable presumption in favor of the
transmission customer has shifted the burden to the transmission
provider to provide evidence that credits for the customer are not
warranted.
---------------------------------------------------------------------------
\132\ Florida Mun. Power Agency v. Florida Power and Light Co.,
74 FERC ] 61,006 at 61,010 (1996) (finding that the integration of
facilities into the plans or operations of a transmitting utility is
the proper test for cost recognition), reh'g denied, 96 FERC ]
61,130 at 61,544-45 (2001), aff'd sub nom. Florida Mun. Power Agency
v. FERC, 315 F.3d 362 (D.C. Cir. 2003).
---------------------------------------------------------------------------
353. To provide clarity regarding how to implement the presumption
that a network customer's facilities are integrated, we make clear that
a network customer may justify application of the presumption by
reference to the existing facilities in the transmission provider's
rates. A customer need only show that its new facilities are similar in
design and purpose to facilities owned by the transmission provider
that are included in rates. A transmission provider may overcome the
network customer's presumed integration by demonstrating, with
reference to its own facilities that meet the integration standard,
that the network customer's new facilities do not meet the standard. To
the extent there are disputes regarding whether a customer's new
facilities are sufficiently similar to those in the transmission
provider's rate base, we encourage transmission providers and customers
to resolve those disputes informally or with the assistance of the
Commission's Dispute Resolution Service.
354. We reject requests to eliminate the presumption of integration
for new customer-owned facilities, as advocated by certain transmission
providers. The planning-related reforms adopted in
[[Page 3026]]
Order No. 890 will ensure that a process exists to jointly plan all
transmission facilities, including new facilities developed by
customers. Comparability requires that transmission providers and
customers alike benefit from a presumption of integration. It is also
appropriate for both the transmission provider and its customers to be
subject to the integration standard to the extent the presumption of
integration is overcome, notwithstanding any coordinated planning of
those facilities. Under Order No. 890, the Commission therefore will
not apply, as some petitioners imply, a different or stricter standard
to a transmission provider's own facilities when a network customer has
been denied credits.
355. We disagree with claims that a presumption of credits for
certain customer-owned facilities will encourage over-building or harm
reliability. Facilities owned by transmission providers have long
enjoyed a presumption of integration, yet petitioners do not object to
the presumption as applied to those facilities. Petitioners offer no
reason to believe that application of a comparable presumption for new
customer-owner facilities would lead to reliability or operational
difficulties, particularly in light of the obligation for transmission
providers under Order No. 890 to plan their transmission systems on an
open and coordinated basis.\133\ We also believe that it is unlikely
that a transmission provider would be required to provide credits to an
interconnecting generator, but be prohibited from rolling the same
credits into its rates. Nevertheless, should any such circumstance
arise, the transmission provider should bring the issue to the
Commission's attention for resolution.
---------------------------------------------------------------------------
\133\ As we discuss in section III.B, planning activities must
be open to all customers, who must provide information regarding
expected uses of the system so that the transmission provider can
plan for their needs.
---------------------------------------------------------------------------
c. Application of the New Test to Existing Facilities
356. In Order No. 890, the Commission concluded that the new test
for determining credits will apply only to transmission facilities
added subsequent to the effective date of Order No. 890. The Commission
found that there is no reason to revisit the determinations with
respect to the number of customer-owned transmission facilities that
have been developed, and resulted in credits negotiated and litigated,
under the prior test that the Commission determined to be just and
reasonable at the time.\134\ On a prospective basis, however, given the
increased planning and coordination required in Order No. 890, the
Commission stated that it is appropriate to apply the new test for
determining credits.
---------------------------------------------------------------------------
\134\ See East Texas Electric Coop., Inc. v. Central and South
West Services, Inc., 114 FERC ] 61,027 (2006).
---------------------------------------------------------------------------
Requests for Rehearing and Clarification
357. Several petitioners contend that it is inappropriate for the
Commission to conclude that the newly announced test for determining
credits under OATT section 30.9 will apply only to transmission
facilities added subsequent to the effective date of Order No. 890,
arguing that the Commission should remedy past undue discrimination
against network service customers such as the failure of transmission
providers to jointly plan facilities with transmission customers.\135\
APPA also asks that the Commission explain why this result is legally
appropriate.
---------------------------------------------------------------------------
\135\ E.g., APPA, East Texas Cooperatives, FMPA, NRECA, TAPS and
TDU Systems.
---------------------------------------------------------------------------
358. NRECA contends that the Commission should apply the new test
for transmission credits to both existing and new facilities, but
clarify that existing credit agreements or determinations will not be
impacted. NRECA argues that Mobile-Sierra concerns can be avoided by
applying the new test to facilities that are built but not yet the
subject of a credits agreement or determination. APPA suggests that
allowing network customers to obtain credits going forward for existing
facilities that are comparable to those the transmission provider
includes in its revenue requirement would be a reasonable remedy for
past discrimination. Noting the Commission's requirement for
transmission providers to remove all generator step-up facility costs
from their transmission rates (not only those costs incurred after the
Commission changed its policy in Order No. 888), TAPS maintains that
the ``correct and fair approach'' is to prospectively remedy such
discrimination by applying the new standard to both existing and new
facilities.\136\ To do otherwise would, in TAPS' view, undermine
comparability.
---------------------------------------------------------------------------
\136\ TAPS also cites Tennessee Gas Pipeline Co., 104 FERC ]
61,063 (2003), order on reh'g, 108 FERC ] 61,177 (2004), order on
reh'g, 110 FERC ] 61,385 (2005) for the proposition that new
policies can be implemented for existing contracts.
---------------------------------------------------------------------------
359. TDU Systems argue that the Commission cannot endorse rates
that it knows are unjust and unreasonable and, therefore, agree that
transmission customers should be credited for transmission facilities
regardless of their vintage to the extent the facilities have not been
subject to a prior determination. TDU Systems contend that Order No.
890 failed to adequately justify allowing rates to remain in place that
reflect undue discrimination. FMPA argue that comparability similarly
requires that the Commission apply the presumption of integration to
existing as well as new customer-owned facilities, since both existing
and new transmission provider-owned facilities are presumed to provide
benefits to the grid.
360. Entergy and Florida Power ask that, to the extent the
Commission applies the new test to transmission provider facilities,
the rule apply only to new facilities constructed by the transmission
provider, not to existing facilities.
Commission Determination
361. The Commission denies rehearing of the decision to apply the
modified test for credits only to transmission facilities added
subsequent to the effective date of Order No. 890. In light of the new
planning and coordination required in Order No. 890, it is appropriate
to apply the new test on a prospective basis.\137\ Existing facilities,
by definition, have been developed without the benefit of the planning-
related reforms adopted in Order No. 890 and, therefore, are not
similarly situated to new facilities developed after the effectiveness
of Order No. 890. As a result, only a network customer's new facilities
will be subject to the presumption of integration standard. Similarly,
the existing presumption applied to the transmission provider's
facilities will continue to allow it to include in its rate base from
the outset all network facilities constructed to meet its obligations
to its customers, provided the presumption is not rebutted.
---------------------------------------------------------------------------
\137\ Order No. 890 at P 758.
---------------------------------------------------------------------------
d. Cost of Customer Facilities Automatically Included in Transmission
Provider Cost of Service Without a Rate Filing
362. Noting that automatic recovery of the costs of credits would
be contrary to the Commission's long-standing policy concerning single-
issue rate adjustments, the Commission declined to generically allow
automatic recovery of the costs of credits associated with integrated
transmission facilities to the transmission provider's cost of service.
The Commission explained that transmission providers continue to have
[[Page 3027]]
the option to propose an automatic adjustment clause in their rates
under FPA section 205 to address the time lag between incurring costs
associated with credits and the transmission provider's next rate case.
Requests for Rehearing and Clarification
363. Florida Power requests that the Commission grant rehearing of
the decision that customer credits do not warrant an exception to the
Commission's general policy regarding single-issue rate adjustments.
Florida Power argues that a transmission provider should not be
required to dedicate the extensive resources required by a full-blown
rate case to recover costs that, in its view, it has been forced to
incur by the Commission's policy and over which it has no control.
364. E.ON U.S. requests that the Commission clarify that payment of
credits is dependent on the transmission provider's ability to recover
the costs of the credits. E.ON U.S. asks that the Commission adopt one
of the following requirements: if the network customer's facilities are
to be eligible for credits, the network customer must petition the
Commission for a declaratory order stating that the transmission
provider will be able to recover costs for the credits in the
transmission provider's next rate case; the transmission provider need
not provide the network customer with credits for its facilities until
the costs of the credits are approved in the transmission provider's
next rate case; or if the cost of the credits are rejected in the
transmission provider's next rate case, the network customer is
required to refund any amounts collected through the transmission
credits, plus interest.
365. APPA asks that the Commission clarify that, if a transmission
provider denies credits for network customer owned facilities, the
transmission provider has a corresponding obligation to take steps to
strip the costs of similar transmission facilities out of its own
transmission revenue requirement where comparability requires such a
result. TAPS argues that nothing in Order No. 890 altered the
transmission provider's existing obligation to remove from its rate
base transmission provider facilities comparable to those for which it
denies credits to network customers.
Commission Determination
366. The Commission affirms its decision in Order No. 890 not to
generically allow automatic rate recovery of the costs of credits
associated with integrated transmission facilities to the transmission
provider's cost of service. As explained in Order No. 890, automatic
recovery would be contrary to our long-standing policy concerning
single-issue rate adjustments, and transmission providers continue to
have the option to propose an automatic adjustment clause in their
rates under FPA section 205 to address the time lag between incurring
costs associated with credits and the transmission provider's next rate
case.\138\ Since transmission providers may choose to add an automatic
adjustment clause to their rates to address any lag in cost recovery,
we reject as unnecessary the alternative proposals offered by E.ON U.S.
---------------------------------------------------------------------------
\138\ See id. at P 766.
---------------------------------------------------------------------------
367. As for APPA's argument regarding the transmission provider's
obligation to remove nonintegrated facilities from its revenue
requirement, as explained above, the denial of credits for a network
customer will no longer trigger an examination of the transmission
provider's own facilities. Rather, the presumption of integration shall
be rebuttable for transmission providers and customers alike. If it
becomes apparent that the transmission provider has included facilities
in its revenue requirement that are ineligible, such as when the
transmission provider relies on its own facilities to demonstrate the
lack of integration for customer-owned facilities, the network customer
or the Commission, as appropriate, may initiate a complaint proceeding
to have such facilities removed from rates.
e. RTO and ISO Issues
368. The Commission concluded in Order No. 890 that it would not be
appropriate to generically exempt all RTOs and ISOs from the revised
requirements regarding credits for network transmission customers. The
Commission stated that it would address issues relating to network
transmission customer credits in the RTO and ISO context in orders
addressing OATT reform compliance filings submitted by each RTO and
ISO. The Commission noted its prior determination that the existing
tariffs of certain RTOs and ISOs provide opportunities for transmission
customers to receive credit or the equivalent (e.g., Transmission
Congestion Contracts, Firm Transmission Rights or Auction Revenue
Rights) for building facilities or upgrades that are consistent with or
superior to Order No. 888 requirements.\139\ The Commission explained
that each RTO and ISO would have the opportunity to show on compliance
that this continues to be the case given the reforms adopted in Order
No. 890.
---------------------------------------------------------------------------
\139\ See id. at P 773, n.447.
---------------------------------------------------------------------------
369. The Commission also addressed a request by NRECA to prohibit
RTOs and ISOs from using a non-public utility's transmission facilities
without compensating the entity because it is not a member of the RTO/
ISO. The Commission found that there is not enough evidence on the
record to make a generic determination on that issue. The Commission
instead concluded it would be appropriate to address such issues on a
case-by-case basis in response to appropriate filings under FPA
sections 205 and 206.
Requests for Rehearing and/or Clarification
370. TAPS is concerned that Order No. 890 suggests that RTOs/ISOs
can justify an exemption from OATT section 30.9 by claiming that firm
transmission rights or similar mechanisms are the ``equivalent'' of
credits under section 30.9. TAPS states that the RTO/ISO tariff
provisions referred to by the Commission relate only to upgrades, which
are funded by a customer but owned by a transmission owner, for a new
service request or generator interconnection. TAPS therefore requests
clarification that the rules with respect to whether a network customer
funding facilities owned by a transmission owner should receive firm
transmission rights in lieu of credits are unrelated to, and should not
be confused with, the requirement in OATT section 30.9 that a network
customer must be compensated for customer-owned facilities in a manner
comparable to transmission owners.
371. NRECA reiterates its argument that the Commission should
require RTOs/ISOs to compensate non-jurisdictional entities for use of
the non-jurisdictional entities' transmission facilities as required by
the principle of comparability. NRECA argues that the issue is purely
legal and that no additional evidence is necessary, since NRECA is not
seeking a ruling that a particular entity is entitled to compensation.
NRECA states that the Commission's reliance on a ``case-by-case''
approach will be illusory if the Commission dismisses a complaint by a
non-jurisdictional utility on the ground that the Commission has no
jurisdiction over the non-jurisdictional entity's rates
[[Page 3028]]
under sections 205 and 206 of the FPA, as it did in Central Iowa Power
Coop.\140\
Commission Determination
---------------------------------------------------------------------------
\140\ Central Iowa Power Coop. v. Midwest ISO, 110 FERC ]
61,093, order on reh'g, 113 FERC ] 61,116 (2005).
---------------------------------------------------------------------------
372. It was not the Commission's intention in Order No. 890 to
prejudge whether Transmission Congestion Contracts, Firm Transmission
Rights or Auction Revenue Rights should be treated as equivalents to
the credits available under section 30.9 of the pro forma OATT. The
Commission simply noted that those mechanisms exist and that the
Commission would determine, as it evaluated compliance filings from
individual ISOs and RTOs, whether such mechanisms served the same
purpose and goal of section 30.9 and, in turn, should be considered
proper substitutes for network customer credits. To the extent TAPS or
others object to proposals made by a particular RTO or ISO, the
appropriate forum to address those concerns is in the relevant
compliance docket.
373. In response to NRECA, we continue to believe that it is
appropriate to consider on a case-by-case basis customer claims that
RTOs or ISOs are using the transmission facilities of a non-public
utility without compensation. It would not be appropriate to address
this issue in a vacuum, without a complete discussion by interested
parties of the legal and policy merits of both sides of this issue.
3. Capacity Reassignment
a. Removal of the Price Cap
374. The Commission concluded in Order No. 890 that it is
appropriate to lift the price cap for all transmission customers
reassigning point-to-point transmission capacity, i.e., resellers. The
Commission found that the price cap had served to reduce transmission
options for customers and impair the development of a secondary market
for transmission capacity. The Commission concluded that removing the
price cap will allow capacity to be allocated to those entities that
value it the most, thereby sending more accurate price signals for
identification of the appropriate location for construction of new
transmission facilities to reduce congestion.
375. To enhance oversight and monitoring by the Commission of the
secondary market for transmission capacity, certain reforms were
adopted to the underlying rules governing capacity reassignments.
First, the Commission required that all sales or assignments of
capacity be conducted through, or otherwise posted on, the transmission
provider's OASIS on or before the date the reassigned service
commences. Second, the Commission required that assignees of
transmission capacity execute a service agreement with the transmission
provider prior to the date on which the reassigned service commences.
Third, in addition to existing OASIS posting requirements, the
Commission required transmission providers to aggregate and summarize
in an electric quarterly report (EQR) the data contained in the service
agreements for reassigned capacity. The Commission explained that,
taken together, these reforms will increase the transparency of
capacity reassignments and facilitate our monitoring of the secondary
market for transmission capacity.
Requests for Rehearing and Clarification
376. Several petitioners request rehearing of the decision to lift
the price cap on reassigned capacity.\141\ Some petitioners question
the Commission's stated justifications for the removal of the price
cap. TDU Systems contend that the non-cost factors cited by the
Commission, including promotion of the secondary market, enabling
customers to better manage the risk of their long term commitments
required by the reform of rollover rights, and sending more accurate
price signals for capacity, do not justify lifting the price cap or
substitute for analyzing the potential for the exercise of market power
before lifting it. TDU Systems, APPA, and NRECA challenge the
Commission's conclusion that removing the price cap for capacity
reassignments will stimulate greater infrastructure investment by
sending more accurate price signals as to the incremental cost of
transmission capacity. They argue that explicit congestion price
signals in RTO markets have failed to stimulate investment and, in any
event, are useless for transmission customers that lack the regulatory
certainty required to facilitate third-party construction of new
facilities. APPA argues that entrenched economic interests often find
it more profitable to pocket the remaining dollars than to invest in
new facilities.
---------------------------------------------------------------------------
\141\ See, e.g., APPA, NRECA, and TDU Systems.
---------------------------------------------------------------------------
377. These petitioners all disagree with the Commission's finding
that the price cap has impaired the development of a secondary market
for transmission. They argue that the Commission cites no support for
this finding and that it failed to address comments in response to the
NOPR stating that non-price limitations on capacity reassignment, such
as the requirement that the assignee use the same source and sink as
original customers, are the real reason that reassignments of capacity
do not occur. APPA also contends that the Commission failed to explain
why the lifting of the price cap is necessary to spur investment in
light of other reforms adopted in Order No. 890, such as a more robust
transmission planning process and the provision of planning redispatch
and conditional firm point-to-point service.
378. TAPS argues that the precedent relied upon by the Commission
in Order No. 890 does not support the decision to lift the price cap
for reassigned capacity. TAPS states that, in Alternatives to
Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines and
Regulation of Negotiated Transportation Services of Natural Gas
Pipelines,\142\ the Commission actually required a market power
analysis to justify market-based rates. TAPS argues that in Interstate
Nat'l Gas Ass'n of America v. FERC,\143\ the D.C. Circuit relied on
empirical evidence to affirm the Commission's decision to lift the cap
on gas pipeline capacity releases. In that case, TAPS argues that:
there was a significant amount of firm capacity going unused,
suggesting that excess capacity could constrain prices and with
evidence that it did in fact put a downward pressure on prices;
evidence existed that new entry could restrain prices; and, the price
cap at issue was lifted only for two years during an experiment. TAPS
argues that similar empirical evidence is required, showing that prices
for secondary transmission capacity above the cap would be competitive
and that new entry could constrain prices.
---------------------------------------------------------------------------
\142\ 74 FERC ] 61,076, reh'g denied, 75 FERC ] 61,024 (1996),
petitions for review denied sub. nom. Burlington Resources Oil & Gas
Co. v. FERC, 172 F.3d 918 (D.C. Cir. 1998).
\143\ 285 F.3d 18 (D.C. Cir. 2002) (INGAA).
---------------------------------------------------------------------------
379. Petitioners generally argue that removal of the price cap may
expose transmission customers to market power and is therefore contrary
to Commission and judicial precedent. APPA and TAPS argue that the
Supreme Court has rejected seller claims justifying higher prices for
electricity based upon the value ascribed to the product by the buyer,
stating that a ``focus on the willingness to pay or ability of the
purchaser to pay for a service is the concern of a monopolist, not a
government agency charged both with assuring the industry a fair return
and with assuring the public reliable and efficient service, at a
reasonable
[[Page 3029]]
price.'' \144\ In their view, this precedent requires the Commission to
maintain the price cap in the absence of hard evidence of a competitive
market for reassigned capacity.
---------------------------------------------------------------------------
\144\ Quoting Gainesville Utilities Department, et al. v.
Florida Power Corp., 402 U.S. 515, 528 (1971).
---------------------------------------------------------------------------
380. Joined by NRECA and TDU Systems, APPA and TAPS argue that the
Commission is allowed to authorize market-based rates only with
empirical proof that existing competition would ensure that the actual
price is just and reasonable and that undocumented reliance on market
forces will not suffice.\145\ In their view, the Commission must engage
in an ex ante competitive analysis to find that the seller lacks market
power, or take sufficient steps to mitigate market power, as well as
adopt sufficient post-approval reporting requirements.\146\ These
petitioners argue that the Commission's reliance on competition among
resellers, continued rate regulation of primary capacity, and the
reassignment-related reforms adopted in Order No. 890 is insufficient
to justify lifting the cap.
---------------------------------------------------------------------------
\145\ Citing Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d
1486 (D.C. Cir. 1984) (Farmers Union) (finding that the Commission
failed to justify relaxation of cost-based regulation of oil
pipeline companies because it did not ensure rates would remain
within the zone of reasonableness).
\146\ Citing California ex. rel. Lockyer, 383 F.3d 1006 (9th
Cir. 2004) (Lockyer).
---------------------------------------------------------------------------
381. With regard to competition among resellers, APPA contends that
transmission capacity is a scarce commodity and demand is currently
inelastic, due in part to substantial load growth. APPA argues that
allowing point-to-point customers to make virtually unlimited profits
from reassignments of their firm service will not further competition
among resellers and, instead, may discourage participation in joint
planning to support expansion or acceptance of increased rates to
support new facilities. APPA acknowledges that firm transmission not
scheduled will be released on a non-firm basis, but argues that is of
little use to LSEs in need of firm transmission to deliver their firm
power supplies.
382. NRECA and TDU Systems argue that it is contradictory for the
Commission to conclude that competition among resellers will assure
just and reasonable prices when, elsewhere in Order No. 890, the
Commission acknowledges congestion and the number of curtailments has
dramatically increased in recent years. These petitioners question what
market forces would constrain prices for secondary capacity at or below
the price of primary capacity if primary capacity is so scarce. They
question how it can be just and reasonable to price secondary rights at
a level higher than the just and reasonable price of primary capacity.
TAPS argues that a market power study of particular transmission paths
is necessary to support a finding that competition among resellers will
restrict market power.
383. With regard to the availability of primary capacity at cost-
based rates, TAPS argues that the Commission has presented no factual
basis to conclude that entry will be timely, likely or sufficient to
defeat price increases due to transmission market power. TAPS contends
that, where capacity is fully subscribed, non-existent capacity cannot
act as a price restraint. APPA argues that any requirement for the
transmission provider to build new facilities in future years has
little if any bearing on the price an LSE is willing to pay for the
next day, week or month to ensure it meets its service obligation.
NRECA and TDU Systems contend that, notwithstanding the planning-
related reforms of Order No. 890, transmission providers can continue
to exert market power by refusing to expand the system to meet
competitors' needs. TDU Systems contends that failure to mandate
expansion of the grid or to encourage third party construction of
needed upgrades will ensure a lack of expansion, allowing the holder of
rights to transmission capacity to exert monopoly power in a secondary
market unprotected by price caps.
384. Petitioners maintain that the revised oversight and reporting
requirements adopted in Order No. 890 are insufficient to protect
transmission customers from the exercise of market power. APPA and
NRECA argue that post hoc reporting cannot prevent real-time harm to
transmission customers and the end-users they serve or relieve the
Commission of the obligation to ensure, at the outset, that the
secondary market for capacity is competitive. TDU Systems similarly
contend that the new posting and reporting requirements are unlikely to
restrain the exercise of market power, since monthly reports will lag
significantly behind the daily and hourly market transactions, even
though greater price transparency may make market power easier to
detect after the fact.
385. MISO argues that, instead of relying on continued regulation
in the primary market and competition in the secondary market to limit
the exercise of market power in the secondary market, the Commission
should provide for a sharing mechanism between the reseller and the
owner of the transmission asset to allocate any market premium obtained
from the resale. MISO contends that revenue sharing would reduce
incentives to engage in hoarding on the part of the reseller and
encourage efficient use of the grid. In its view, sharing market
premiums would have a solid ground in equity, ensuring that the owners
of transmission, constrained by cost-based rates, are not unduly
discriminated against in favor of the reseller.
386. APPA also contends that the use of value-of-service pricing
for firm transmission service that LSEs require to meet their loads'
needs violates FPA section 217(b)(4) because it does not enable the
LSEs to secure the firm transmission rights they need to serve their
loads as Congress intended. While not specifically opposing the
Commission's decision to lift the price cap on reassignments of
transmission capacity, South Carolina E&G makes a similar request that
removal of the price cap be subject to the Commission's assurances that
the resulting increased use of the grid will not compromise service to
native load customers. In its view, an active secondary market could
crowd the limits of the grid and increase the likelihood of
curtailments. Southern Carolina E&G argues that FPA section 217
requires that native load service not be marginalized a result of any
increased use of the grid.
387. If the Commission declines to reinstate the price cap on
assignments of transmission capacity, TAPS asks that the Commission
take two steps to offer consumer protection. First, TAPS asks the
Commission to require utilities seeking to reassign transmission
capacity to demonstrate a lack of transmission market power. TAPS
argues that this demonstration should examine each point of receipt/
point of delivery pair as a distinct market, unless the public utility
can show that alternative paths provide meaningful substitutes. Second,
TAPS asks the Commission to lift the price cap only for short-term
services and only for a period of two years. TAPS suggests that, at the
end of this period, the Commission should assess whether prices for
reassigned capacity are competitive and whether the experiment produced
the desired increase in reassigned capacity.
Commission Determination
388. The Commission affirms the decision in Order No. 890 to remove
the price cap on reassignments of transmission capacity. We continue to
believe that removal of the price cap will give market participants
additional options for acquiring transmission. Point-to-point
transmission service
[[Page 3030]]
customers will have increased incentives to resell their service
whenever others place a higher value on it. Existing transmission
therefore will be put to better, more efficient use. Point-to-point
customers also may be willing to commit to buy additional transmission
service (such as for periods long enough to get rollover rights) since
they are able to resell above the price cap during periods in which
they do not need the capacity. On this basis alone, we find that
establishing a competitive market for secondary transmission capacity
will send more accurate signals that promote efficient use of the
transmission system by fostering the reassignment of unused capacity.
389. We agree with petitioners that restricting reassignment to the
same point of receipt and point of delivery has limited, and may
continue to limit, the number of reassignments that take place. It does
not follow, however, that the price cap is irrelevant or that lifting
the cap will not encourage additional reassignments of transmission
capacity. Petitioners acknowledge that the secondary market for
transmission capacity is underdeveloped. Even if the price cap is not
the sole cause for this lack of development, it is at least a
contributing factor. While other reforms adopted in Order No. 890 also
will facilitate use of and investment in the transmission system, this
does not mean that lifting the price cap on capacity reassignments is
unnecessary or unimportant. The reforms adopted in Order No. 890,
including the decision to lift the price cap, work together to enhance
customer options and the transmission provider's operation of the grid.
390. We are sensitive, however, to the concerns expressed by
petitioners and grant rehearing to limit the period during which
reassignments may occur above the cap. In Order No. 890, the Commission
directed staff to closely monitor the quarterly reassignment-related
data submitted by transmission providers to identify any problems in
the development of the secondary market and to prepare a report on
staff's findings for the Commission within 6 months of the receipt of
two years worth of data, i.e., by May 1, 2010. Upon further
consideration, we conclude that it is most appropriate to lift the
price cap on reassignments of capacity only to accommodate this study
period and amend section 23.1 of the pro forma OATT to reinstate the
price cap as of October 1, 2010. Upon review of the staff report and
any feedback from the industry, the Commission can determine whether it
is appropriate to continue to allow reassignments of capacity above the
price cap beyond that date.
391. We disagree that a market power study or other empirical
competition analyses are required to lift the price cap on capacity
reassignments during this study period. Contrary to petitioners'
assertions, market power analyses are not the only method to ensure
that market-based rates remain just and reasonable.\147\ In INGAA,\148\
the court affirmed the Commission's removal of price ceilings for
short-term capacity releasing shippers in the natural gas market
without requiring sellers to submit market power analyses, recognizing
non-cost factors such as the need to lift price ceilings to facilitate
movement of capacity into the hands of those who value it most. The
court concluded that these non-cost factors, combined with the
limitation of negotiated rates to the secondary market, distinguished
the case from Farmers Union.\149\ Similarly, continuing rate regulation
of the transmission provider's primary capacity, competition among
resellers, and reforms to the secondary market for transmission
capacity, combined with enforcement proceedings, audits, and other
regulatory controls, will assure that prices in the secondary market
for transmission capacity remain within a zone of reasonableness.\150\
---------------------------------------------------------------------------
\147\ See Alternatives to Traditional Cost-of-Service Ratemaking
for Natural Gas Pipelines and Regulation of Negotiated
Transportation Services of Natural Gas Pipelines, 74 FERC ] 61,076
at 61,227-36 (1996). The Commission ultimately determined in that
case that a market power analysis was required in order to allow a
pipeline to use market-based pricing instead of cost-of-service
rates. The Commission has not proposed to allow transmission
providers to engage in sales of primary capacity at market based
rates and, as explained below, sufficient protections exist to
ensure the secondary market for transmission capacity remains
sufficiently competitive without requiring market power analyses
from each reseller.
\148\ 285 F.3d at 33.
\149\ INGAA, 285 F.3d at 31-34.
\150\ See Order No. 890 at P 811.
---------------------------------------------------------------------------
392. Petitioners inappropriately discount the importance of these
regulatory protections, particularly the continued rate regulation of
primary transmission capacity. Unlike gas pipelines, transmission
providers are obligated to construct new facilities to satisfy a
request for service if that request cannot be satisfied using existing
capacity. The pro forma OATT does not, and will not, permit the
withholding of transmission capacity by the transmission provider and
effectively establishes a price ceiling for long-term reassignments at
the transmission provider's cost of expanding its system. Petitioner
arguments to the contrary assume non-compliance with the transmission
provider's obligations under the pro forma OATT. If a customer has
evidence of such non-compliance, it should bring the matter to the
Commission's attention through a complaint or other appropriate
procedural mechanism. Absent such evidence, the Commission concludes
that the continued rate regulation of the primary market, and the
transmission provider's obligation to expand its system to accommodate
service requests, adequately mitigates any market power that resellers
may have in the long-term secondary market.
393. Pending the completion of upgrades, we acknowledge that delays
associated with constructing new facilities could limit the downward
effect that the transmission provider's cost of expansion has on
prices. Resellers could attempt to gain market power through economic
or physical withholding of their primary capacity when congestion
arises. As the Commission found in Order No. 890, however, competition
among resellers, as well as the ability of customers desiring
additional capacity to access primary capacity using conditional firm
point-to-point service or the modified planning redispatch implemented
in Order No. 890, will mitigate the exercise of market power in the
interim.\151\ Moreover, any primary capacity that is not scheduled is
made available to other customers on a non-firm basis, frustrating any
attempts to withhold capacity.\152\
---------------------------------------------------------------------------
\151\ See Order No. 890 at P 809, 812.
\152\ See id. at P 811.
---------------------------------------------------------------------------
394. Reforms to the rules governing reassignments and associated
reporting obligations also increase our regulatory oversight of the
secondary market, allowing the Commission to effectively monitor that
market for any attempts to exercise market power. All reassignments
must now be conducted through or otherwise posted on OASIS and
assignees must execute service agreements prior to the date on which
service commences. Transmission providers must provide information
regarding reassignments in their EQRs.\153\ As noted above, Commission
staff will also closely monitor the
[[Page 3031]]
quarterly reassignment-related data submitted by transmission providers
and prepare a report on staff's findings for the Commission's
consideration. The Commission takes seriously the possibility that
resellers may attempt to exercise market power in the secondary market
for transmission capacity. We continue to believe, however, that the
regulatory protections in place and our increased oversight of this
market will limit the potential for market power abuse during the
period in which the price cap is lifted. There is no need for
particularized market power studies regarding secondary transmission
capacity, as suggested by TAPS.
---------------------------------------------------------------------------
\153\ As TDU Systems point out, the reports will lag behind the
daily and hourly transactions in the market. As explained above,
competition among resellers and regulatory protections embedded in
the pro forma OATT will ensure that prices remain within the zone of
reasonableness in the immediate near-term. The reports will enable
the Commission to identify trends in the market and inefficiencies
that may occur. Furthermore, if parties see that particular holders
of transmission capacity are attempting to exercise market power
through hoarding or other tactics, they can report such instances to
the Office of Enforcement for investigation without delay.
---------------------------------------------------------------------------
395. We disagree with NRECA and TDU Systems that the potential for
secondary prices to rise above primary capacity prices indicates that
rates may not be just and reasonable. As the courts have recognized,
prices in a competitive market should rise during periods when capacity
is truly scarce in order to ensure that capacity is being allocated
appropriately.\154\ The precedent cited by petitioners clearly permits
the Commission to implement alternative pricing structures provided
that safeguards are in place to ensure that rates remain within a zone
of reasonableness.\155\ We continue to believe that the regulatory
framework governing the reassignment of transmission capacity, combined
with our increased oversight and enforcement authority, will ensure
that the rates for secondary transmission capacity remain within the
zone of reasonableness. At the same time, lifting the price cap will
give primary transmission customers greater incentives to commit to
long-term service because they will be able to resell above the cap
during periods when they do not need the capacity.
---------------------------------------------------------------------------
\154\ See INGAA, 285 F.3d at 18, 32 (``[B]rief spikes in moments
of extreme exigency are completely consistent with competition,
reflecting scarcity rather than monopoly * * * A surge in the price
of candles during a power outage is no evidence of monopoly in the
candle market.'').
\155\ See Farmers Union, 734 F.2d at 1509-10; INGAA, 285 F.3d at
32-34; Lockyer, 383 F.3d at 10-13; see also Environmental Action v.
FERC, 996 F.2d 401, 410 (D.C. Cir. 1993).
---------------------------------------------------------------------------
396. We decline to adopt a mechanism to share revenues from
capacity reassignments with the transmission provider. Allocation of
the entire reassignment premium to the reseller is appropriate because
it promotes an efficient allocation of transmission capacity, while
sharing of the premium could make a potential seller less likely to
resell even though another customer places a higher value on the
transmission service. The Commission addressed a similar request in
Order No. 636-A and concluded that releasing shippers in the gas market
should be entitled to receive the proceeds from reselling their
capacity.\156\ Notwithstanding differences in the secondary market for
transmission capacity, we believe that a similar approach should be
followed for transmission providers, particularly since they already
receive their full cost-of-service through payments for the underlying
primary capacity. In any event, it would only be fair to share premiums
with the transmission provider if losses were also shared when capacity
was resold for less than the cost to the reseller of the capacity. Such
sharing could lead to under-recovery of costs contrary to the premise
of cost-of-service rates.
---------------------------------------------------------------------------
\156\ See Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation; and
Regulation of Natural gas Pipelines After Partial Wellhead
Decontrol, Order No. 636-A, 57 FR 36128 (August 12, 1992) FERC
Stats. & Regs., Regulations Preambles January 1991-June 1996 ]
30,950 at 30,562 (1992) (``Since the pipeline is not releasing the
capacity, no efficiency or other pro-competitive goal would be
furthered by allowing it to retain incremental proceeds.'').
---------------------------------------------------------------------------
397. Finally, we do not believe that assignments will impose risks
upon native load customers in contravention of FPA section 217 by
increasing the likelihood of curtailments. Transmission providers
should be planning the operation of their system to accommodate all
reserved uses. Simply reassigning primary capacity from one customer to
another should not alter the transmission provider's ability to satisfy
its service commitments. We also disagree that lifting the price cap on
reassignments of capacity will make it more difficult for LSEs to
obtain firm capacity to serve their load or otherwise marginalize
native load service, as APPA suggests. Lifting the price cap should
encourage primary capacity holders to make more, not less, transmission
available to other customers, including LSEs. While it is true that
secondary capacity may at times be more expensive than primary
capacity, establishing a competitive market for secondary transmission
capacity will benefit all customers, including LSEs, by sending more
accurate signals that promote efficient allocation of transmission
capacity.
b. Lifting the Price Cap for Merchant Function and Affiliates
398. The Commission declined in Order No. 890 to adopt the NOPR
proposal to retain price caps for capacity resold by a transmission
provider's merchant function or its affiliates. After reviewing the
comments submitted in response to the NOPR, and further considering its
experience regulating capacity reassignments, the Commission concluded
that retaining price caps for this portion of the market would continue
to impair development of the secondary market and that price caps for
such capacity are not otherwise necessary to ensure just and reasonable
rates. The Commission found that there are no significant market power
concerns to justify retaining the price caps for any transmission
customer, noting that the Commission did not distinguish between
affiliated and non-affiliated transmission customers when the
Commission initially found in Order Nos. 888 and 888-A that excess
capacity reserved could be reassigned.
Requests for Rehearing and Clarification
399. The same petitioners challenging the Commission's decision to
lift the price cap for reassignments of capacity object specifically to
lifting the price cap for reassignments by the transmission provider
and its affiliates. APPA argues that this decision will result in more
limited primary capacity, since it will be in the economic interest of
the transmission provider's corporate family for the merchant function
and/or affiliates of the transmission provider to buy any primary
capacity that is available. APPA contends that such transactions would
technically satisfy the transmission provider's obligation to make
primary capacity available to customers, but effectively convert
primary capacity into secondary capacity not subject to a price cap.
APPA acknowledges that the Commission found in Order No. 890 that the
Standards of Conduct will mitigate the ability of an affiliate to hoard
capacity, but argues that the Commission failed to explain how such
mitigation would occur.
400. TAPS expresses similar concern that the transmission provider
will have an incentive to sell primary capacity to its merchant
function or affiliates to get around the rate ceiling on primary
capacity. If the secondary market is clearing at rates above the
transmission provider's rate ceiling, TAPS argues that the parent
corporation will have the incentive to put as much capacity in the
hands of its merchant function or affiliates as possible, reducing the
amount of price-restraining primary capacity and producing higher
revenues for the parent corporation for sales of monopoly transmission
service. In TAPS' view, costs associated with hoarding will not
encourage resale if withholding profitably raises prices in the
secondary market. TAPS also argues that the Commission's decision is
[[Page 3032]]
inconsistent with its conclusion elsewhere in Order No. 890 that
transmission providers have an incentive to over-designate CBM, which
TAPS states is a form of hoarding. TAPS complains that, although the
Commission stated in Order No. 890 that it will monitor for hoarding
behavior by transmission providers and their affiliates, it proposed no
remedy in the event they engage in this behavior.
401. APPA, TAPS and TDU Systems argue that lifting the price cap
for the transmission provider's merchant function and affiliate sales
also will discourage transmission providers from constructing
transmission capacity in an attempt to raise prices in the secondary
market. They contend that corporate families profiting more from
transmission capacity resold by its merchant function or unregulated
affiliates will have a disincentive to build new transmission that
would lower those resale prices. APPA argues that much of Order No. 890
is devoted to attempting to ensure that transmission providers do not
discriminate in order to favor their own generation, yet lifting the
resale cap for the transmission provider's merchant function and
affiliates gives transmission providers incentives to favor their own
and their affiliates' sale of reassigned capacity at unregulated rates
and to limit construction of new transmission facilities and upgrades
to keep the rates for such reassignments high. NRECA and TDU Systems
agree, arguing that shareholders and senior management will be
indifferent as to whether the profits are from primary or secondary
markets, or from transmission or generation, and will seek to drive
profits to monopoly levels if possible. TDU Systems argue that the fact
that both affiliated and non-affiliated transmission customers were
permitted in Order No. 888 to engage in reassignments of capacity is
irrelevant because the ability to reassign capacity invoked few market
power concerns so long as the price cap remained.
402. APPA also requests clarification as to whether the
transmission capacity that a transmission provider's merchant function
uses to serve the transmission provider's own retail loads is eligible
for reassignment. If so, APPA argues that it is unduly discriminatory
to deny network customers the ability to reassign their capacity. APPA
contends that network service was developed specifically to provide to
other LSEs a transmission service comparable to the transmission
service that public utilities provide themselves.
Commission Determination
403. The Commission affirms the decision in Order No. 890 to lift
the price cap for capacity resold by any point-to-point transmission
customer, including the transmission provider's merchant function and
its affiliates. We continue to believe that retaining the price cap for
this portion of the market would impair development of the secondary
market and is not otherwise necessary to ensure just and reasonable
rates. In light of the protections discussed above, we find there are
not significant market power concerns that would justify retaining
resale price caps for any transmission customer.
404. While it is true that lifting the price cap for reassignments
of capacity could provide an economic incentive for the transmission
provider's merchant function or its affiliates to acquire transmission
capacity in an attempt to exercise market power, the same is true for
any customer. Under the Standards of Conduct, affiliated and
unaffiliated customers have equal access to transmission-related
information and, through the OASIS, equal opportunity to acquire
primary transmission capacity. Thus, any customer could engage in
speculative purchasing in an attempt to gain market power. The
Commission found in Order No. 890 that the entire secondary market is
now sufficiently competitive, in light of the reforms adopted, market
forces, and other considerations, to justify lifting the price cap for
all transmission customers reselling capacity.\157\ As we explain
above, there are sufficient structural and regulatory protections to
ensure that no holder of capacity is able to exercise market power,
regardless of whether the customer is affiliated with the transmission
provider. The transmission provider must offer all firm (including
long-term conditional firm) and non-firm capacity that is available and
award that capacity in a non-discriminatory manner, which will
undermine any customer's attempt to exercise market power. It therefore
would not be appropriate to distinguish between classes of customers
when lifting the price cap for reassignments.
---------------------------------------------------------------------------
\157\ See Order No. 890 at P 809. There the Commission
distinguished its decision from the determination in Order Nos. 888
and 888-A to implement the price cap on all reassignments based on a
finding that the entire secondary market was not sufficiently
competitive to justify market-based pricing.
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405. We disagree that our decision will lead to lower investment in
new facilities by transmission providers. The pro forma OATT places an
affirmative obligation on transmission providers to expand their system
in order to accommodate requests for service. In addition, Order No.
890 requires transmission providers to establish an open and
transparent planning process to ensure that transmission plans are
developed on a non-discriminatory basis. Transmission providers are
also required to file reports with the Commission if they are late
processing requests for new service and pay penalties if they are
consistently late with service request studies. We conclude that these
protections are adequate to ensure that transmission providers do not
forego upgrades in an attempt to increase the value of capacity that
has been assigned to their affiliates.
406. Because the Commission has found the secondary market for
transmission capacity to be sufficiently competitive, it would not be
appropriate to distinguish between classes of customers reselling their
capacity. As we state above, however, the Commission takes seriously
allegations of market abuse and we reiterate our intent to be vigilant
in overseeing this market. If the Commission finds evidence of market
abuse, we will exercise our enhanced authority by restricting the
ability of an offending reseller (and possibly its affiliates) to
participate in the secondary market for transmission capacity or
imposing other remedies, including civil penalties, as appropriate.
Should any customer believe that capacity is being preferentially
allocated to a transmission provider's affiliates, that particular
holders of transmission capacity are attempting to exercise market
power through hoarding or other tactics, or that the transmission
provider is failing to meet its expansion obligations, the customer
should bring the matter to the Commission's attention through a
complaint or other appropriate procedural mechanism. We direct staff to
include in its report any evidence of abuse in the secondary market for
transmission capacity.
407. With regard to APPA's request for clarification regarding the
ability of the transmission provider's merchant function to reassign
transmission capacity used to serve the transmission provider's retail
load, we reiterate that only point-to-point transmission customers may
reassign their transmission capacity.\158\ To the extent the
transmission provider's merchant function or a network customer has
acquired point-to-point transmission, either may resell that capacity
in the secondary market.
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\158\ See Order No. 890 at P 825.
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[[Continued on page 3033]]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]
[[pp. 3033-3082]] Preventing Undue Discrimination and Preference in Transmission
Service
[[Continued from page 3032]]
[[Page 3033]]
c. Contracting and Posting Issues
408. As noted above, the Commission required in Order No. 890 that
all sales or assignments of capacity be conducted through or otherwise
posted on the transmission provider's OASIS on or before the date the
reassignment commences. The Commission thus eliminated the ability of
transmission customers to assign transmission rights to another party
with subsequent notification to the transmission provider. The
Commission also directed transmission providers, working through NAESB,
to develop appropriate OASIS functionality to allow such postings.
Transmission providers were not required to implement this new OASIS
functionality or any related business practices until NAESB develops
appropriate standards.
409. The Commission also required that assignees of transmission
capacity execute a service agreement prior to the date on which the
reassigned service commences. Transmission customers with market-based
rate tariffs were no longer permitted to execute and implement
assignments of capacity without involving the transmission provider,
subject to after-the-fact reporting and posting. The Commission
explained that this effectively returns the specified capacity to the
transmission provider for the purpose of reassignment to the assignee
and eliminates the need for the assigning party to have a rate schedule
governing reassigned capacity on file with the Commission. The
transmission provider's OATT will govern the reassigned service, with
the assignee paying the transmission provider for service at the
negotiated rate and the transmission provider billing or crediting the
reseller with any difference between the negotiated rate and the
reseller's original rate. All the non-rate terms and conditions that
otherwise would apply to the transmission provider's sale of
transmission capacity continue to apply in the case of a reassignment.
410. In addition to already existing OASIS posting requirements,
the Commission required transmission providers to aggregate and
summarize in an EQR the data contained in the service agreements for
reassigned capacity. The Commission directed that the quarterly report
be submitted in the EQR so that it is readily accessible to the
Commission and the public. The Commission also revised section 23 of
the pro forma OATT to address reassignments of transmission capacity
and added a pro forma service agreement for reassignments in a new
Attachment A-1.
Requests for Rehearing and Clarification
411. Several petitioners request rehearing and clarification of the
requirement that there must be a service agreement in place between the
transmission provider and the assignee prior to the assignment
commencing. Bonneville argues that requiring transmission providers to
execute service agreements with assignees is too onerous and that it is
unnecessary for the Commission to monitor more closely the secondary
market for transmission capacity. Bonneville further argues that it
would be virtually impossible to execute a service agreement for daily
or hourly reassignments, harming the market for reassignments of short-
term transmission. Bonneville also suggests that requiring a written
contract for assignments may cause OASIS transactions between a
reseller and assignee to be non-binding and force the transmission
provider to maintain two systems for transactions, one electronic and
one for paper transactions.
412. Bonneville also contends that if an assignee fails to return
an executed service agreement under the Commission's new rules,
transmission service could not commence even though the reseller and
assignee concluded an assignment on OASIS. Bonneville claims that,
under the Commission's OASIS standards, the transmission provider has
no ability to invalidate, refuse, decline, retract or annul an
assignment on OASIS and, therefore, no ability to recall the assigned
capacity from the assignee and return it to the reseller. Bonneville
states that OASIS would show the reservation in the name of the
assignee and the assignee would be able to schedule transmission
without a service agreement, effectively nullifying the requirement.
413. Joined by EEI, Bonneville suggests that the Commission clarify
that the requirement to execute a service agreement with the assignee
is satisfied by a previously executed umbrella agreement between the
transmission provider and the assignee and that the execution of a
service agreement covering a particular assignment is not required. EEI
contends that this would be consistent with the current requirement for
customers taking short-term firm and non-firm service under the pro
forma OATT. EEI requests clarification that, regardless of whether the
assignee has executed a service agreement with the transmission
provider, the same OASIS posting requirements would apply to
reassignments as apply to any reservation of transmission service. EEI
argues that an assignee should be required to inform the transmission
provider through an OASIS posting of the terms and conditions of the
assignment so that the transmission provider and other customers are
informed of the existence of a reservation for transmission capacity.
414. Constellation argues that there is no basis in the record for
the Commission to adopt formal assignment procedures for short-term
reassignments. Constellation asks that the Commission grant rehearing
to allow short-term and temporary assignments of transmission capacity
to occur without a formal reassignment of the transmission service
agreement. Constellation suggests that the Commission consider other
means of separating the filing requirements for capacity reassignment
from those for market-based rates tariffs, such as by establishing
standardized tariff terms in its regulations and authorizing entities,
upon notice to the Commission, to adopt those regulations as their
filed tariff for reassignments.
415. Several petitioners object to the billing mechanism adopted
for capacity reassignments. Bonneville argues that transmission
providers should be allowed to continue billing the reseller for the
assigned capacity. Bonneville contends that requiring transmission
providers to bill at the negotiated rate will insert the transmission
provider into the financial arrangements of the reseller and the
assignee, obligating the transmission provider to monitor the parties'
business arrangements and adjust its own operations to compensate.
Bonneville also contends that transmission providers are not set up to
charge assignees rates that are different from the normal transmission
rate. If a robust assignment market develops, Bonneville states that
transmission providers could have to charge dozens of different rates
varying from day to day or even hour to hour. Bonneville suggests that
both the reseller and assignee would likely be purchasing other
transmission in addition to the assigned capacity, requiring the
transmission provider to charge at least two different rates to the
same customer. Bonneville contends that significant changes will have
to be made to all transmission providers' billing systems at
substantial cost to the industry to accommodate the Commission's reform
of the rules governing capacity reassignment.
416. EEI and Southern suggest that transmission providers be
required to charge the assignee at the same rate that
[[Page 3034]]
the reseller originally agreed to pay and allow the reseller and
assignee to arrange for any difference between the original price and
the negotiated reassignment price. Southern argues that requiring the
transmission provider to act as settlement agent unnecessarily
complicates and duplicates the transmission provider's burdens and
responsibilities, noting the Commission declined to impose such an
obligation when third party generators provide planning
redispatch.\159\ EEI argues that the service agreement with the
reseller terminates when the assignee executes a new service agreement
and, as a result, the transmission provider has no contractual basis to
collect revenues from the reseller if the reseller has resold its
capacity at a price lower than the price it agreed to pay the
transmission provider.\160\ Joined by Washington IOUs, EEI suggests
that requiring the transmission provider to charge the assignee at a
rate different from the price stated in its OATT would violate either
the discount rule or the ceiling price. If the Commission declines to
change its billing rules on rehearing, EEI requests that Schedules 7
and 8 of the pro forma OATT be amended to provide that ceiling prices
and discounting rules do not apply in the context of reassigned
transmission capacity.
---------------------------------------------------------------------------
\159\ Citing Order No. 890 at P 1160.
\160\ Citing id. at P 816, n.496.
---------------------------------------------------------------------------
417. EEI contends that the Commission's concerns with respect to
the reporting of the price of reassigned capacity can be addressed
without requiring the transmission provider to become involved in the
payment stream related to the reassignment. EEI argues that all
jurisdictional resellers of transmission report those transactions in
their EQRs. If the Commission wants all capacity reassignments on a
system to be in a single report, EEI argues it can require the assignee
to inform the transmission provider of the price and other terms of
service and the transmission provider can include this information in
its EQR.
418. Washington IOUs distinguish between long-term and short-term
reassignments, arguing that different rules should be adopted for each
type of transaction. For long-term reassignments, Washington IOUs argue
that transmission providers should only be required to take on a
bilateral relationship with an assignee where all rates, terms and
conditions of the assignment are the same as the original rates, terms
and conditions of the purchase of primary capacity. Otherwise, they
contend the transmission provider may be unable to recover the rate
owed to it in the event of a dispute between the reseller and assignee.
For short-term reassignments, they argue the transmission provider
should continue to bill the reseller for the assigned capacity
scheduling rights, with the assignee paying the reseller directly.
Washington IOUs contend that NAESB distinguishes between long-term and
short-term reassignment transactions, which they argue is appropriate
to ensure transmission providers are not unduly burdened by being
forced to act as a middleman between resellers and assignees.
419. TranServ contends that the NAESB standards distinguish between
resales of scheduling rights and transfers of all obligations,
including financial responsibilities. TranServ states that, under the
NAESB standards, a resale does not alter the financial obligation for
the capacity reassigned, which remains with the reseller. TranServ
argues that the billing mechanism adopted in Order No. 890
inappropriately shifts this financial obligation to the assignee,
unduly burdening the transmission provider with the responsibility to
manage settlement of the reassignment.
420. EEI asks the Commission to refer to NAESB the issue of whether
any modifications to the OASIS protocols are required to implement the
modifications to transmission reassignments required in Order No. 890.
EEI requests that NAESB be directed to report to the Commission on
whether modifications are required to implement transmission
reassignments being posted before-the-fact rather than after-the-fact
and if so, NAESB's estimated timeline for development of such
modifications.
421. Several petitioners complain about the cost to the
transmission provider of providing the accounting and billing for
capacity reassignments. EEI and Washington IOUs contend that the
Commission's billing rules require the transmission provider to
subsidize the administrative costs of the reassignment by collecting
and distributing payments on behalf of the reseller and assignee.
Washington IOUs argue that the transmission provider's limited
resources would be better used in areas more central to the
transmission provider's core responsibilities. MidAmerican asks that
the Commission expressly limit the ability of assignees to further
assign capacity, arguing that the administrative tracking and posting
of additional reassignments would be costly. To the extent the
Commission requires transmission providers to continue to credit and
charge revenues from reassignments of capacity, E.ON U.S. and TranServ
ask the Commission to clarify that transmission providers should be
compensated for the accounting services they provide to act as billing
agents for reassignments of capacity. Unless a compensation mechanism
is spelled out in the pro forma OATT, these petitioners argue that the
financial obligations between the reseller and assignee should remain
with those parties.
Commission Determination
422. The Commission affirms the decision in Order No. 890 to
require assignees to execute a service agreement with the transmission
provider governing reassignments of transmission capacity prior to
scheduling use of that capacity. We provide clarification of this
requirement, however, in response to the concerns raised by
petitioners. In Order No. 890, the Commission required that all
reassignments be accomplished by the assignee executing a service
agreement with the transmission provider that will govern the provision
of reassigned service.\161\ The Commission did not intend to impose
contracting obligations that are more onerous than the acquisition of
primary transmission capacity, which may be accomplished through
execution of a service agreement followed by scheduling on OASIS. We
clarify that it is equally sufficient for an assignee to execute a
service agreement governing its reassignments of capacity generally and
to complete a particular assignment through the OASIS. However, as with
reservations of primary transmission capacity, there remains a
threshold requirement to execute a service agreement with the
transmission provider in order to commit the assignee to abide by the
terms and conditions of the transmission provider's OATT governing the
reassignment of transmission service.
---------------------------------------------------------------------------
\161\ See id. at P 816. The Commission adopted corresponding
revisions to section 23.1 of the pro forma OATT requiring the
execution of a service agreement prior to the date on which the
reassigned service commences that will govern the provision of
reassigned service.
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423. It would not be appropriate to relieve assignees of the
obligation to execute a service agreement with the transmission
provider since such agreements establish the necessary contractual
relationship between the assignee and the transmission provider. As we
explain above, sales of reassigned capacity now take place under the
transmission provider's OATT and, thus, there must be a contractual
relationship between these parties. This does not mean, however, that
all of the
[[Page 3035]]
terms and conditions of a particular assignment must be stated in the
service agreement. Like short-term firm and non-firm reservations of
primary capacity, the transmission provider and assignee may rely on
OASIS to provide information regarding the reseller, quantity, and
price associated with a particular reassignment of service. This
information would then become part of the binding agreement between the
transmission provider and assignee governing the assignment,\162\ just
as confirmation of short-term firm and non-firm transactions on OASIS
constitute binding contractual commitments. Because execution of a
service agreement with the transmission provider governing
reassignments of capacity is a threshold requirement for an assignee
wishing to accomplish a particular reassignment on OASIS, Bonneville's
concern regarding the failure of an assignee to return its service
agreement is misplaced. The assignee in that instance would have no
right to schedule a reassignment on OASIS since it has not first
executed the appropriate service agreement with the transmission
provider.
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\162\ The EQR for reassignments of transmission capacity must
contain all relevant transaction data, whether stated in the service
agreement or related OASIS schedule.
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424. Some of the confusion regarding these contracting requirements
may have been caused by the Commission's reference in section 23.1 of
the revised pro forma OATT to a service agreement ``that will govern
the provision of reassigned service,'' which could be interpreted to
refer to transaction-by-transaction service agreements for
reassignments. Inclusion of the words ``Long-Term Firm'' in both the
title of the form of service agreement and the attached specifications
in the new Attachment A-1 to the pro forma OATT adopted in Order No.
890 may have added to the confusion by potentially implying that use of
the service agreement is limited to long-term firm point-to-point
transactions instead of also applying to short-term firm point-to-point
and non-firm point-to-point reassignments, as intended by the
Commission.\163\ We revise section 23.1 of the pro forma OATT and the
title of Attachment A-1 to make clear that use of the form of service
agreement for reassigned capacity, and associated posting of schedules
and transaction information on OASIS, should be similar to the use of
such agreements for primary capacity.\164\
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\163\ See pro forma OATT Attachment A-1, Form of Service
Agreement for the Resale, Reassignment or Transfer of Long-Term Firm
Point-to-Point Transmission Service.
\164\ As with the form of service agreement for firm point-to-
point transmission service, we retain the specifications attachment
for the form of service agreement governing reassignments. We
understand that long-term agreements for reservations of primary
capacity rely on the specifications attachment, so we would expect
similar practices to be used regarding long-term reassignments of
transmission capacity. As with any transaction, however, actual uses
of primary and secondary capacity should be scheduled on OASIS
consistent with applicable business procedures.
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425. The execution of a service agreement by the assignee does not
itself terminate the reseller's service agreement, as EEI argues. The
reseller's service agreement remains in place, granting the reseller
scheduling rights for the reserved capacity and obligating the reseller
to pay for that reservation. During the term of the assignment, the
reseller will continue to be billed under its agreement with the
transmission provider. The assignment of service simply transfers to
the assignee some or all of the reseller's scheduling rights for the
period of the reassignment and, in return, obligates the assignee to
pay the transmission provider the negotiated rate. In order to prevent
over-recovery by the transmission provider, the transmission provider
must therefore credit the reseller the reassignment rate, which leaves
the reseller with the net difference between the resale rate and the
reseller's original rate.\165\ If the assignee defaults and fails to
pay for the reassigned capacity, the transmission provider should
reverse the credit to the reseller to reflect the lack of payment by
the assignee.\166\
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\165\ If the reseller and assignee agree to a full transfer of
the reseller's rights and obligations, the reseller would only make
payments to the extent the transfer is executed at a lower rate than
the rate agreed to between the reseller and transmission provider,
to ensure that the transmission provider receives the full contract
price agreed to by the reseller. If the full transfer is executed at
a rate in excess of the reseller's contract with the transmission
provider, the transmission provider must credit the reseller with
the additional revenue as a result of the transfer.
\166\ The transmission provider may take action against the
assignee as it would any other default under the pro forma OATT. We
recognize that, in this instance, the transmission provider may have
little incentive to pursue collection since it will recover its
original contract rate from the reseller, but it could transfer to
the reseller its legal rights to enforce the assignee's payment
obligations.
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426. We disagree that these billing requirements are unduly
burdensome. While it is true that the transmission provider may be
required to bill at different rates, that is already the case under the
pro forma OATT. Transmission providers are permitted to offer discounts
from the rates stated in their OATT, provided they offer such discounts
to all eligible customers. Offering discounts thus creates different
rates for different customers depending on when they negotiate service.
The transmission provider therefore should already have mechanisms in
place to bill customers based on rates other than those stated in its
OATT. In any event, the need to bill assignees directly for
reassignments is inextricably linked to the decision to require that
all reassignment transactions take place pursuant to the rate on file
in the transmission provider's OATT, rather than bilateral agreements
between customers.\167\ We therefore do not intend for the discount
rule or the price ceilings otherwise stated in the transmission
provider's OATT to apply to reassignments of capacity. We have revised
schedules 7 and 8 of the pro forma OATT accordingly.
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\167\ It is therefore irrelevant that payments for third-party
planning redispatch are settled bilaterally, since the underlying
planning redispatch service is not provided under the transmission
provider's OATT.
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427. We clarify that, to the extent necessary, the costs incurred
by the transmission provider to account and bill for reassignments of
transmission capacity should be included in the transmission provider's
cost of service, just like accounting and billing costs for any other
service under the transmission provider's OATT. We decline
MidAmerican's request to prohibit further assignments of reassigned
capacity. Order No. 888 allowed for multiple reassignments under the
pro forma OATT and MidAmerican does not justify departing from this
practice. Just as the original transmission customer may find that it
has excess capacity it can reassign, so may an assignee. Denying the
assignee's right to further assign its scheduling rights would inhibit
customers who value the capacity most from accessing it and thereby
contradict the Commission goal of creating a competitive secondary
market for transmission capacity.
428. With regard to OASIS modifications necessary to allow for the
reassignment of transmission capacity, the Commission in Order No. 890
already directed transmission providers working through NAESB to
develop appropriate OASIS functionality to allow for reassignment-
related postings.\168\ We understand that this work is on-going and
expect any necessary modifications to NAESB's business practices that
are necessary to reflect our rulings in this order will be adopted
prior to the submission of those standards for Commission review. In
the interim, transmission providers should identify in their business
practices any
[[Page 3036]]
procedures necessary to accomplish the reassignment of capacity by
their customers.
---------------------------------------------------------------------------
\168\ See Order No. 890 at P 815.
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d. Market-Based Rate Tariffs
429. Because purchasers of transmission capacity in the secondary
market will execute a service agreement directly with the transmission
provider, the Commission stated in Order No. 890 that there will no
longer be a need for the assigning party to have on file with the
Commission a rate schedule governing reassignment capacity. The
Commission explained that the transmission provider's OATT will govern
the reassigned service.
Request for Rehearing and Clarification
430. EPSA and Powerex question how sellers with market-based rates
are to proceed regarding the removal of the price cap stated in their
market-based rates tariffs. In order not to violate their market-based
rate tariffs, these petitioners contend that sellers may be obligated
to file revisions of their tariffs and receive an order approving those
revisions prior to reselling transmission above the cap. Powerex also
suggests that existing market-based rate tariffs require a seller of
transmission capacity to continue reporting in its quarterly reports
the name of an assignee. Powerex and EPSA request that the Commission
deem void, as of the effective date of Order No. 890, the provisions in
each individual seller's market-based rate tariffs that impose a cap on
resale prices and reporting obligations. Petitioners suggest that these
resellers be permitted to update their market-based rate tariffs at
such time as the tariff is amended or with their next triennial update.
Commission Determination
431. In Order No. 890, the Commission explained that reassignments
of transmission capacity will now be governed by the transmission
provider's OATT.\169\ Each assignee must execute a service agreement
directly with the transmission provider, which we clarify above may be
an umbrella service agreement governing multiple reassignment
transactions scheduled on OASIS. As a result, the sale of reassigned
capacity is made by the transmission provider pursuant to the terms and
conditions of its OATT, not by the reseller under its market-based rate
tariff. Although the reseller may negotiate the relevant price with the
assignee, the reassignment itself is governed by the transmission
provider's OATT. The reseller's market-based rate tariff is no longer
relevant or controlling. The Commission therefore explained in Order
No. 890 that the reseller does not need to have on file with the
Commission a rate schedule governing reassigned capacity.
---------------------------------------------------------------------------
\169\ See id. at P 816, n.496.
---------------------------------------------------------------------------
432. In Order No. 697, the Commission affirmed this approach,
explaining that it is no longer appropriate to include in the market-
based rate tariff transmission-related services.\170\ The Commission
stated that reassignments of capacity are, instead, provided for in the
revised pro forma OATT and that capacity holders seeking to reassign
transmission capacity should adhere to the provisions of Order No. 890.
Because these reassignment-related provisions of the market-based rate
tariff were no longer needed, the Commission directed sellers to revise
their market-based rate tariffs to remove the provisions at the time
they otherwise revise their tariffs to conform them to the standard
provisions adopted in Order No. 697.\171\
---------------------------------------------------------------------------
\170\ See Market-Based Rates For Wholesale Sales Of Electric
Energy, Capacity and Ancillary Services By Public Utilities, Order
No. 697, 72 FR 39,904 (July 20, 2007), FERC Stats. & Regs. ] 31,252
(2007).
\171\ Id. at P 920.
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433. To the extent confusion remains as to the relationship between
the market-based tariff and the transmission provider's OATT, we
reiterate that, as of the effective date of the reforms adopted in
Order No. 890, all reassignments of capacity must take place under the
terms and conditions of the transmission provider's OATT. To the extent
a reseller has a market-based tariff on file, the provisions of that
tariff, including a price cap or reporting obligations, will not apply
to the reassignment since such transactions no longer take place
pursuant to the authorization of that tariff. As the Commission
directed in Order No. 697, sellers should amend their market-based rate
tariff to remove provisions regarding the reassignment of capacity when
they otherwise revise their tariffs to conform them to the standard
provisions adopted in Order No. 697.
4. ``Operational'' Penalties
a. Unreserved Use Penalties
(1) Unreserved Use of Transmission Service and Inappropriate Use of
Network Service
434. In order to eliminate a potential source of discretion in the
implementation of the pro forma OATT and to enhance the Commission's
enforcement of OATT obligations, the Commission clarified, in Order No.
890, the application of unreserved use penalties. The Commission
determined that a transmission customer would be subject to unreserved
use penalties in any circumstance where the transmission customer uses
a transmission service that it has not reserved. Specifically, a
transmission customer will be subject to an unreserved use penalty in
circumstances where a transmission customer has a transmission
reservation, but uses transmission service in excess of its reserved
capacity. A transmission customer also will be subject to an unreserved
use penalty if the transmission customer uses transmission service
without the appropriate transmission reservation.
435. The Commission declined to exempt any class of customers from
the potential assessment of unreserved use penalties, including LSEs
serving native load in multiple control areas, and noted that the
transmission provider itself is subject to the same penalties when it
takes transmission service under its OATT. The Commission stated that a
network customer or transmission provider that inappropriately uses
network transmission service to support off-system sales may be
required to disgorge unjust profits from such sales, as the Commission
may determine on a case-by-case basis. The Commission stated that it
would evaluate the appropriateness of civil penalties in addition to
unreserved use penalties on a case-by-case basis. The Commission
concluded that it is appropriate to subject both a network customer and
transmission provider inappropriately using network transmission
service to unreserved use penalties because such action potentially
uses or acquires, without an appropriate reservation, transmission
service that could be allocated to other customers. The Commission
modified the language of section 30.4 of the pro forma OATT to clarify
that network customers are subject to unreserved use penalties when
they schedule delivery of off-system non-designated purchases using
transmission capacity reserved for designated network resources.
436. The Commission clarified that a network customer may use the
undesignated portion of a remote network resource to serve network load
using secondary network service and may use the undesignated portion of
the resource for other non-network service purposes, such as third-
party sales, as long as the network customer acquires the appropriate
point-to-point service. The Commission also noted that, because the
transmission provider does not have to ``take service'' under its OATT
for the transmission of power
[[Page 3037]]
that is purchased on behalf of bundled retail customers, it is free to
use the undesignated portion of a remote network resource to serve its
bundled retail customers. The Commission affirmed that, if the
transmission provider desires to use a remote network resource for non-
native load purposes, such as third-party sales, it must acquire the
appropriate point-to-point service.
437. In order to ensure that the transmission provider has a basis
for charging an unreserved use penalty, the Commission modified section
13.4 of the pro forma OATT to provide that a customer that takes
unreserved point-to-point transmission service and does not have a
service agreement with the transmission provider is deemed to have
executed the transmission provider's form of service agreement for
point-to-point service. The Commission also clarified that a customer
that uses more transmission service than it has reserved is also
subject to charges for ancillary services based on the period of
unreserved use. The Commission modified section 3 of the pro forma OATT
to reflect that rule.
Requests for Rehearing and Clarification
438. AWEA seeks clarification of the Commission's statement that
intermittent resources could avoid unreserved use penalties by
reserving sufficient transmission capacity to deliver the resource's
full output. AWEA asks that the Commission confirm that it did not
intend to require resources to always reserve point-to-point
transmission service based on the maximum potential output in order to
avoid unreserved use penalties. AWEA contends that such a practice
would be cost prohibitive for a wind generator, which often operates at
less than full output, and could require multiple transmission
reservations, up to full nameplate capacity, on multiple transmission
paths for generators that market their output at multiple trading
points from day to day. AWEA contends that determining whether a
positive imbalance event results in an unauthorized use of transmission
depends on whether the transmission provider is contractually obligated
to deliver a resource's actual or full output, or only a fixed amount
of power, and, to the extent the positive generation imbalance is
physically delivered from point A to point B, whether such delivery is
covered by a transmission service reservation.
439. If the Commission does not grant the requested clarification,
AWEA requests rehearing to the extent Order No. 890 authorizes
transmission providers to impose unreserved use penalties for every
instance of positive generator imbalance. AWEA argues such a
requirement would be inconsistent with the Commission's refusal to
delineate the specific circumstances that constitute unreserved use of
the transmission system. AWEA further argues that applying unreserved
use penalties in every instance of positive generation imbalance would
subject generators to duplicative charges for an imbalance and would
render uneconomic substantial numbers of wind power transactions. AWEA
argues such a policy would be unjust, unreasonable and unduly
discriminatory against wind power generators that have no ability to
control the actual output of their facilities.
440. TDU Systems argue that it is unjust and unreasonable for the
Commission to subject LSEs to penalties for inadvertent uses of network
service when managing loads and resources across a neighboring control
area. TDU Systems contend that serving native load in multiple control
areas requires managing resources across those boundaries and the
flexibility to respond to changes in service requirements on a timely
basis in a cost-efficient manner comparable to the way in which
transmission providers use network service to manage their retail
native load service obligations. In their view, inadvertent takes of
transmission service in excess of reservations occur for reasons beyond
the control of the LSE and, therefore, assessing unreserved use
penalties is inappropriate. TDU Systems also object to the Commission's
statement that it would not, as a general policy, exempt an LSE's
unreserved use from potential civil penalties. TDU Systems argue that
the imposition of civil penalties on LSEs that inadvertently violate
the prohibition on unauthorized use would be unjust and unreasonable on
its face. TDU Systems suggest that payment for the increment of service
actually used but not reserved makes the transmission provider whole
without visiting further penalties on behavior that is by definition
unintentional.
441. TDU Systems argue that inadvertent takes of transmission
service in excess of reservations by an LSE serving native load in
multiple control areas should be treated as an energy imbalance in the
control area in which the energy imbalance occurs, rather than as an
unauthorized use of point-to-point service. TDU Systems object to the
Commission's characterization of energy imbalance charges as
compensation to the transmission provider for the additional expense it
incurs to compensate for a transmission customer's failure to schedule
sufficient energy to serve its load, arguing that imbalance charges
contain a penal, above-cost component that make the transmission
provider more than whole. In their view, the more onerous unreserved
use charges should be reserved for intentional over-scheduling of
transmission reservations.
442. In order to prevent inadvertent uses from occurring in the
first place, TDU Systems contend that transmission providers should be
required, as a condition of being able to impose penalties, to use
software designed to identify unreserved uses. TDU Systems suggest that
such software could disallow tags for service that exceeds reserved
levels. They argue that the Commission missed the point by rejecting
this suggestion in Order No. 890 based on the expectation that the
reforms adopted would reduce the level of unreserved use penalties for
instances of inadvertent uses. TDU Systems contend that the
Commission's stated objective of discouraging disorderly use of the
transmission system would be better achieved by requiring the use of
software designed to identify inadvertent uses, rather than the
assessment of steep unreserved use penalties.
443. TDU Systems further argue that prior Commission approval of
penalties should have been required, arguing that due process requires
nothing less than Commission notice, review, and approval, as well as
an opportunity for a hearing, before application of any unreserved use
penalty. TDU Systems argue that the burden should be on the
transmission provider to justify any requested penalties, rather than
on the transmission customer to disprove the reasonableness of a
penalty through the complaint process.
444. TAPS requests clarification of the Commission's statement that
the transmission provider is free to use the undesignated portion of a
remote network resource to serve its bundled retail customers since it
does not have to ``take service'' under its OATT for the transmission
of power that is purchased on behalf of bundled retail customers. TAPS
contends that, although a transmission provider is not required to take
network service to meet the needs of its bundled retail loads, it does
have to abide by all of the requirements of designating network
resources for such purpose \172\ and that the non-tariff
[[Page 3038]]
service the transmission provider uses for itself must be comparable to
the network service provided to its transmission customers.\173\ TAPS
argues that the transmission provider's own use of non-designated
resources (or portions of resources) to meet bundled retail therefore
must be on a non-firm basis supported by secondary network service, as
is the case for network customers.\174\ TAPS requests rehearing to the
extent the Commission intended to allow transmission providers
preferential use of the transmission system.
---------------------------------------------------------------------------
\172\ Citing pro forma OATT section 28.2; Wisconsin Public Power
Inc. SYSTEM v. Wisconsin Public Svc. Corp., 84 FERC ] 61,120 (1998).
\173\ Citing pro forma OATT section 28.3.
\174\ Citing In re SCANA Corp., 118 FERC ] 61,028 (2007); Idaho
Power Co., 103 FERC ] 61,182 (2003).
---------------------------------------------------------------------------
445. TAPS also requests clarification that the Commission's
discussion of secondary network service was intended to address only
what a network customer (or the transmission provider) can and cannot
do with respect to the host transmission provider's system and does not
place any limitations on the use of resources on the remote systems.
TAPS asks that the Commission clarify that the host transmission
provider cannot impose a penalty for scheduling delivery of designated
or undesignated portions of a customer's remote resources when such
delivery does not utilize the host transmission provider's transmission
system.
446. Washington IOUs contend that established rules in place since
Order No. 888 have allowed network customers to use a firm transmission
path reserved for a designated network resource for any power
(including economy purchases) as long as the use did not exceed the
amount of the firm network reservation. Washington IOUs argue that the
Commission reversed this long-standing policy by prohibiting the use of
a reserved firm path for network capacity to deliver power from a non-
designated resource, which, in turn, improperly and unreasonably
devalued network service in comparison to point-to-point service.
Washington IOUs contend that whether the megawatts using the reserved
transmission capacity are coming from a designated network resource or
a replacement power source is largely irrelevant because this
distinction does not affect grid use and causes no harm to any other
customer so long as the quantity does not exceed the amount of the
reservation. Washington IOUs state that the Commission places no
restrictions on the resource used to provide the megawatts flowing over
a capacity reserved in a long-term firm point-to-point reservation and
that it would degrade the quality of network service to impose such
restrictions, and associated penalties, on network customers. In their
view, providing penalties for such uses of the transmission system
would provide a windfall to other transmission customers because the
circumstances giving rise to these penalties cause no harm to other
customers.
Commission Determination
447. The Commission declines to distinguish between intentional and
unintentional unreserved transmission uses and reiterates that all
unreserved uses will be subject to operational penalties. We conclude
that maintaining penalties for any unreserved use of transmission
service will create the right incentives for customers to take
appropriate measures to minimize any unreserved use before it occurs,
whether intentional or not. As the Commission noted in Order No. 890,
any unreserved use of transmission service can harm reliability and
disrupt the allocation of transmission rights.\175\ It is therefore
appropriate to maintain penalties for both intentional and
unintentional unreserved uses. The Commission was sensitive, however,
to the concerns of commenters, determining in Order No. 890 that
penalties should be based on the period of unreserved use rather than
the period for which service is reserved, which could be much longer.
This penalty structure more closely approximates the penalty charge
with the impact on the transmission system while maintaining the
correct incentive for transmission customers to take the necessary
steps to ensure that they reserve appropriate service.
---------------------------------------------------------------------------
\175\ See Order No. 890 at P 838.
---------------------------------------------------------------------------
448. The Commission continues to believe that it would not be
appropriate to exempt any class of customers from unreserved use
penalties. While we appreciate that intermittent resources have limited
ability to precisely forecast or control generation levels, they are
able to reserve sufficient transmission capacity to deliver their full
output in the event it is produced, thereby mitigating potential
unreserved use penalties. In this regard, intermittent resources are no
different than any other generator and, thus, application of unreserved
use penalties is not discriminatory. Exempting these or any other type
of resource from unreserved use penalties would diminish incentives to
reserve adequate transmission to deliver the resource's output,
potentially creating reliability problems for the transmission provider
and discriminating in favor of the resource in the allocation of
transmission rights.
449. The Commission also disagrees that imposing unreserved use
penalties on generators for inadvertent positive generation imbalances
is duplicative of imbalance charges that may be assessed. As the
Commission explained in Order No. 890, imbalance charges and unreserved
use penalties serve different purposes.\176\ Imbalance charges result
from a transmission customer's failure to schedule adequate capacity
for energy deliveries, whereas unreserved use penalties result from a
transmission customer's failure to reserve adequate capacity for energy
deliveries. Even though a transmission customer may be assessed charges
for both an imbalance and an unreserved use in a particular scenario,
that is appropriate because the transmission customer has delivered
energy in excess of what it reserved and scheduled. In that instance,
application of an imbalance charge in addition to an unreserved use
penalty recognizes that the transmission customer both failed to
reserve adequate transmission as well as failed to properly schedule
its energy deliveries.
---------------------------------------------------------------------------
\176\ See id. at P 837.
---------------------------------------------------------------------------
450. We acknowledge, as TDU Systems argue, that imbalance charges
contain a penalty, above-cost component, but disagree that this alone
justifies relieving a customer of an unreserved use penalty. As a
threshold matter, we note that revenues from imbalance charges or
unreserved use penalties in excess of the transmission provider's costs
or relevant transmission rate are distributed to transmission
customers, not retained by the transmission provider. More to the
point, however, imbalance charges and unreserved use penalties are
associated with different actions and, as such, are designed to
compensate the transmission provider for different things, while also
providing appropriate incentives to transmission customers. We continue
to believe that both imbalance charges and unreserved use penalties
should apply to the extent the customer's reservation and schedule are
insufficient.
451. We also acknowledge that, in certain circumstances,
inadvertent unreserved uses by an LSE serving load in multiple control
areas may be beyond the LSE's control at the moment they occur. This
does not mean, however, that penalties should not apply to such
unreserved uses. Like any customer, the LSE is able to protect itself
against unreserved use penalties by reserving sufficient capacity. We
also reject the argument that civil penalties would be unjust and
unreasonable on their face if applied to inadvertent unreserved uses
[[Page 3039]]
by an LSE. As with any civil penalties, the Commission will consider
the facts and circumstances before it when determining whether to
impose a civil penalty for unreserved use of transmission service.
452. As the Commission explained in Order No. 890, we will not
require transmission providers to use software designed to identify
unreserved uses as a condition of being able to impose operational
penalties.\177\ It is the obligation of the transmission customer, not
the transmission provider, to ensure that the customer has reserved the
transmission service that it uses. Moreover, we do not have sufficient
evidence before us now to decide that, as a general matter, development
and implementation of such software would be more appropriate than
assessing penalties for inadvertent unreserved uses, which we note were
significantly reduced by the reforms adopted in Order No. 890. For the
same reasons expressed in Order No. 890, we reject TDU Systems'
argument that Commission approval is required prior to assessing an
unreserved use penalty.\178\
---------------------------------------------------------------------------
\177\ See id. at P 835.
\178\ See id. at P 836.
---------------------------------------------------------------------------
453. With regard to TAPS' concern about the transmission provider's
use of the system to serve native load, Order No. 890 did not disturb
the requirement from Order No. 888 that transmission providers serving
native load must designate network resources and load. Although
transmission providers are not required to take service under their
OATT in such circumstances, we reiterate that, to the extent a
transmission provider takes power from a non-designated network
resource to serve bundled retail load, such power must be on a non-firm
basis comparable to secondary network service.\179\ To the extent
necessary, the Commission clarifies that Order No. 890 was not intended
to grant transmission providers greater flexibility than other network
customers when using undesignated network resources or undesignated
portions of designated network resources to serve bundled retail load.
---------------------------------------------------------------------------
\179\ See, e.g., Order No. 888 at 31,745.
---------------------------------------------------------------------------
454. We also clarify, as TAPS requests, that the Commission's
discussion of secondary network service in Order No. 890 was intended
to address only what a network customer (or the transmission provider)
can and cannot do with respect to the host transmission provider's
system.\180\ The host transmission provider cannot impose a penalty for
scheduling delivery of designated or undesignated portions of a
customer's remote resources when such delivery does not utilize the
host transmission provider's transmission system. Unreserved uses of
the host transmission provider's system can, however, be charged an
unreserved use penalty, and section 13.4 of the pro forma OATT provides
that the customer using the unreserved service shall be deemed to have
executed a service agreement with the host transmission provider to
govern that service. To the extent necessary, we clarify that all
unreserved uses of the host transmission provider's system are to be
considered uses of firm point-to-point transmission service, even if
the customer is taking network service or non-firm point-to-point
service for the reserved portion of its service.
---------------------------------------------------------------------------
\180\ See Order No. 890 at P 839.
---------------------------------------------------------------------------
455. We disagree with Washington IOUs that a network customer's use
of firm transmission capacity reserved for a designated network
resource to deliver power from a non-designated resource causes no harm
to other customers. The Commission has long required network customers
to use secondary network service to deliver energy from non-designated
resources to serve network load.\181\ To allow network customers to use
the firm transmission capacity reserved for designated network
resources in such circumstances would unduly preference the network
customer over other potential users of that firm capacity. In such a
case, the transmission customer could avoid potential curtailments
because the purchased energy is scheduled with a higher curtailment
priority under NERC guidelines than it would receive had the
transmission customer used secondary network or non-firm point-to-point
transmission service.\182\ In addition, the transmission customer uses
service that would have potentially been unavailable if it had
requested service as required.
---------------------------------------------------------------------------
\181\ See pro forma OATT section 28.4; Order No. 888 at 31,748.
\182\ See MidAmerican Energy Co., 112 FERC ] 61,346 (2005);
PacifiCorp, 118 FERC ] 61,026 (2007).
---------------------------------------------------------------------------
(2) Penalty Rate for Unreserved Use of Transmission Service
456. The Commission determined in Order No. 890 that it will
continue giving transmission providers discretion in setting their
unreserved use penalty rates to the extent they are consistent with
that order. If a transmission provider elects to charge unreserved use
penalties, the Commission explained that such penalty charges must be
based on the period of unreserved use rather than the period for which
service is reserved, subject to certain principles. First, the
unreserved use penalty for a single hour of unreserved use will be
based on the rate for daily firm point-to-point service, even if the
transmission provider has a rate for hourly firm point-to-point service
on file. Second, as a general rule, more than one assessment for a
given duration (e.g., daily) will increase the penalty period to the
next longest duration (e.g., weekly).
457. The Commission affirmed the requirement that a transmission
provider wishing to charge unreserved use penalties must explicitly
state the penalty rate in its OATT. The Commission also retained the
current policy established in Allegheny Power Sys., Inc. that the
unreserved use penalty rate may not be greater than twice the firm
point-to-point rate for the period of unreserved use.\183\ The
Commission established a rebuttable presumption that unreserved use
penalties no greater than twice the firm point-to-point rate for the
penalty period are just and reasonable. The Commission further stated
that transmission providers proposing an unreserved use penalty in
excess of twice the relevant firm point-to-point rate for pervasive
unreserved use could do so in a filing under section 205 of the FPA.
Transmission providers proposing such a rate must establish that a
higher penalty rate is required to combat pervasive unreserved use of
transmission and why the standard rate that penalizes repeated
unreserved use is not adequate to discourage repeated instances of
unreserved use of transmission service.
---------------------------------------------------------------------------
\183\ Allegheny Power Sys., Inc., 80 FERC ] 61,143 at 61,545-46
(1997).
---------------------------------------------------------------------------
Requests for Rehearing and Clarification
458. TDU Systems contend that a 200 percent penalty rate is
excessive and unnecessary to the extent it is based on periods greater
than the unreserved use period. TDU Systems argue that, if system
integrity and reliability are the bases upon which the penalty policy
is founded, then penalties for a single hour should be based on the
rate for hourly transmission service, and so forth. TDU Systems state
that that they generally agree that a transmission customer must face a
penalty in excess of the firm point-to-point rate in order to have an
incentive to reserve the appropriate amount of service, but contend
that the Commission fails to justify charging 200 percent penalties on
periods greater than the unreserved use period. In their view, a 200
percent penalty might be
[[Page 3040]]
appropriate if based only on the period of unreserved use but is
excessive and unnecessary when applied to periods greater than the
unreserved use.
459. TDU Systems further contend that a 200 percent penalty is
excessive in any event for an isolated inadvertent use. In their view,
the Commission should limit any application of the 200 percent penalty
charge to intentional or persistent, repeated unauthorized uses. TDU
Systems claim that the Commission misconstrued this proposal in its
comments on the NOPR. TDU Systems states that they do not argue that
only repeated unreserved uses should be subject to a penalty. Rather,
they argue that the 200 percent penalty in particular should apply only
to intentional or persistent unauthorized uses.
460. E.ON U.S. maintains that the Commission failed to address
whether, or how, a transmission provider may recover a penalty from
customers whose unauthorized use of transmission service also includes
unauthorized use of ancillary services. E.ON U.S. asks the Commission
to clarify that ancillary service rates for unauthorized uses are
subject to the same price cap (twice the applicable ancillary services
rate for the period of unauthorized use) and pricing criteria that
apply to the unauthorized transmission penalty rates. If not, E.ON U.S.
contends that the charge for such unauthorized uses of ancillary
services will not discourage unauthorized use of ancillary services.
Commission Determination
461. The Commission affirms the adoption of a rebuttable
presumption that unreserved use penalties up to two times the
transmission provider's applicable point-to-point service rate are just
and reasonable. This penalty structure provides appropriate incentives
to transmission customers to purchase the correct amount of
transmission capacity, yet is not unduly harsh in light of changes to
the definition of the penalty period. Prior to Order No. 890,
transmission providers could assess unreserved use penalties based on
the length of the transmission customer's reservation. The Commission
reformed that practice in Order No. 890, significantly relaxing
unreserved use penalties by requiring that they be based on the period
of use.\184\ The Commission balanced the penalty rate of 200 percent
against that reform, and we continue to believe that the balance struck
provides transmission customers a just and reasonable incentive to
reserve the correct amount to transmission capacity.
---------------------------------------------------------------------------
\184\ See Order No. 890 at P 846. The Commission explained that
penalty charges must be based on the period of unreserved use,
subject to certain principles. First, the unreserved use penalty for
a single hour of unreserved use will be based on the rate for daily
firm point-to-point service, even if the transmission provider has a
rate for hourly firm point-to-point transmission service on file.
Second, as a general rule, more than one assessment for a given
duration (e.g., daily) will increase the penalty period to the next
longest duration (e.g., weekly). For example, a customer having two
unreserved daily uses within a week could be charged an unreserved
use penalty equal to the weekly firm point-to-point rate plus a
penalty component up to 100 percent of that weekly firm point-to-
point rate, for a total unreserved use penalty charge up to 200
percent of the point-to-point weekly rate.
---------------------------------------------------------------------------
462. It is therefore appropriate to apply the 200 percent penalty
rate to all unreserved uses, whether inadvertent or intentional. As
explained above, all unreserved uses have the potential to impair
reliability and disrupt the allocation of transmission rights and,
therefore, all should be subject to a penalty. Underlying TDU Systems'
request for rehearing on this point is an apparent belief that
persistent unauthorized uses should be subject to higher penalties to
distinguish them from inadvertent uses. In response, we note that the
penalty structure adopted in Order No. 890 already provides for
increased penalties for persistent unreserved uses since more than one
assessment for a given duration will increase the penalty period to the
next longest duration. To the extent a transmission provider believes
additional penalties are necessary to prevent pervasive unauthorized
use, it may make a filing under FPA section 205 to propose such
additional penalties.\185\
---------------------------------------------------------------------------
\185\ See id. at P 849.
---------------------------------------------------------------------------
463. In response to E.ON U.S., the Commission clarifies that all
charges for ancillary service costs associated with unreserved uses
must be based on the actual costs of the ancillary service attributable
to the unreserved use, i.e., not subject to the 200 percent penalty
rate. For example, a transmission customer with one hour of unreserved
use may be charged for one hour of ancillary service costs associated
with that use, even if the customer is charged twice the daily point-
to-point rate for the underlying unreserved use. We believe the 200
percent penalty as applied to the firm point-to-point rate based on the
period of unreserved use is an adequate incentive to accurately
schedule without applying an additional penalty on the related
ancillary service charge. If a transmission provider wishes to impose
charges for ancillary services as a component of an unreserved use
penalty, the transmission provider must expressly state so in its OATT.
b. Distribution of Operational Penalties
464. Consistent with its determination regarding the distribution
of imbalance penalties, the Commission concluded in Order No. 890 that
transmission providers must distribute all unreserved use and late
study penalties they collect, whether from the transmission provider's
merchant function or other transmission customers. The Commission
required that unreserved use penalties be distributed to all non-
offending transmission customers, whether or not affiliated with the
transmission provider (including the transmission provider's native
load) and required all late study penalties to be distributed to non-
affiliates.
465. The Commission required the transmission provider to make an
annual compliance filing and, in that filing, propose: (1) A mechanism
to identify non-offending transmission customers; (2) a method to
distribute the unreserved use penalty revenues it receives to the
identified transmission customers; and (3) how it will distribute late
study penalties to unaffiliated transmission customers. The Commission
also required the transmission provider to make an annual filing that
provides information regarding the penalty revenue the transmission
provider has received and distributed.\186\ The Commission declined to
require the transmission provider to make an annual filing to propose a
distribution method for unreserved use and late study penalties,
concluding instead that the annual informational filing requirement was
sufficient.
---------------------------------------------------------------------------
\186\ The annual informational filing must provide: (1) A
summary of penalty revenue credits by transmission customer; (2)
total penalty revenues collected from affiliates; (3) total penalty
revenues collected from non-affiliates; (4) a description of the
costs incurred as a result of the offending behavior; and (5) a
summary of the portion of the unreserved penalty revenue retained by
the transmission provider. See Order No. 890 at P 864.
---------------------------------------------------------------------------
466. In order to make the transmission provider whole prior to
distribution of unreserved use penalty revenues, the Commission allows
the transmission provider to retain the base firm point-to-point
transmission service charge and to distribute any revenue collected
above the base firm point-to-point transmission service charge to all
non-offending customers. The transmission provider is required to
distribute the entire amount it pays under section 19.9 of the pro
forma OATT for completing service request studies on an untimely basis.
The Commission also prohibited
[[Page 3041]]
transmission providers from recovering for ratemaking purposes or
through any service under the Commission's jurisdiction any amount it
or an affiliate pays as an operational penalty.
Requests for Rehearing and Clarification
467. TDU Systems argue that any retention of revenues from the
unreserved use penalty by affiliated, non-offending transmission
customers will dilute the impact of the penalty by returning some of it
to the corporate family. While unaffiliated transmission customers pay
100 percent of the penalty, TDU Systems contend that affiliated
transmission customers would pay less than the full operational penalty
since some of the costs will be returned to the corporate family. TDU
Systems claim that this discount constitutes undue discrimination and
is inconsistent with comparability.
468. Claiming that it would be time-consuming and burdensome for a
transmission provider to refile, on an annual basis, its methodology
for assessing and distributing operational penalties, Ameren and EEI
ask the Commission to clarify that the distribution methodology is to
be proposed in a one-time compliance filing. In their view, the annual
informational filing is more appropriately limited to implementation of
the distribution methodology, i.e., the amount of penalties assessed,
the amounts distributed to customers, and the amounts retained by the
transmission provider. Ameren and EEI suggest that any changes to the
distribution methodology proposed after acceptance of the one-time
compliance filing be submitted in a separate filing under FPA section
205. EEI also asks the Commission to clarify whether the one-time
compliance filing proposing the transmission provider's distribution
methodology is to be submitted when the transmission provider makes the
other tariff modifications to comply with Order No. 890 or at some
other date.
469. MidAmerican seeks a number of clarifications regarding the
requirement to propose a distribution methodology in a compliance
filing. MidAmerican asks the Commission to clarify that the
transmission provider must wait for a Commission order before
commencing the implementation of its filed revenue distribution plan.
MidAmerican also questions whether it would be acceptable for a
transmission provider to use the full annual compliance period to
identify the non-offending transmission customers or, if not
acceptable, whether the billing month should be used. MidAmerican
suggests that an ``offending transmission customer'' should be
classified as such for the entire reporting period and not for a subset
of the reporting period. Finally, MidAmerican contends that it should
be acceptable to allocate the penalty revenues between non-offending
network customers and point-to-point customers based on the total
megawatt-hours that each of these customer groups scheduled during the
compliance period. If the Commission disagrees, MidAmerican seeks
clarification of how to allocate the penalty revenues between the two
customer groups. With regard to the annual informational filing,
MidAmerican asks the Commission to confirm that it is acceptable to
submit the annual informational filing some months following the
compliance filing. MidAmerican also suggests that both the compliance
filing and the informational filing can be submitted any time during a
calendar year for penalties that were imposed during the prior calendar
year.
470. MidAmerican requests further clarification that penalty
revenue distribution should be treated as credits toward a future
billing cycle. MidAmerican also suggests that the Commission adopt a
reasonable threshold below which penalty revenue distributions become
disproportionately burdensome, such as any calendar year when the total
penalties are less than $10,000. Below that threshold, MidAmerican
suggests that the transmission provider should have the option to make
the payment to the transmission provider's regional reliability
organization, which it states would contribute to reducing payments for
reliability that benefits all customers.
Commission Determination
471. As some petitioners note, the discussion of the process for
distributing operational penalties in Order No. 890 is somewhat
unclear. We grant rehearing to explain more precisely the process
transmission providers must follow in filing their unreserved use
penalty rates, operational penalty distribution methodologies, and
annual compliance reports with the Commission.
472. First, if a transmission provider elects to impose unreserved
use penalties, it must submit to the Commission a tariff filing under
FPA section 205 stating the applicable unreserved use penalty rate.
Second, each transmission provider also must submit a one-time
compliance filing under FPA section 206 proposing the transmission
provider's methodology for distributing revenues from late study
penalties and, if applicable, unreserved use penalties. This one-time
compliance filing can be submitted at any time prior to the first
distribution of operational penalties. Transmission providers should
request an effective date for this distribution mechanism as of the
date of the filing and may begin implementing the methodology
immediately, subject to refund if the Commission alters the
distribution mechanism on review. The distribution mechanism, as
accepted by the Commission, will remain effective until the
transmission provider files changes to the proposed structure or the
Commission directs any such changes on its own motion. Finally, each
transmission provider must report on its penalty assessments and
distributions in an annual compliance report to be submitted on or
before the deadline for submitting FERC Form-1, as established by the
Commission's Office of Enforcement each year. This annual compliance
report should be filed under in the same docket as the docket in which
the proposed one-time compliance filing is submitted.
473. Although we will continue to allow transmission providers to
propose a mechanism through which they will identify who is a ``non-
offending'' transmission customer for purposes of making unreserved use
penalty distributions, this should not be based on the entire calendar
year, as MidAmerican suggests. For instance, for purposes of
calculating penalty revenue distributions, it would not be appropriate
for transmission providers to lump together all customers who caused
any degree of unreserved use over the course of a year into one group
and then distribute the penalty revenues to the remaining customers. We
believe that it is best to consider the remaining details of a
transmission provider's distribution mechanism, including the
particular period used to identify non-offending customers (e.g.,
quarterly, monthly, etc.), on a case-by-case basis on review of the
one-time compliance filing proposing the distribution mechanism.
474. The Commission rejects requests for rehearing of the
determination to allow revenues for unreserved use penalties to be
distributed to all non-offending customers, including affiliates. We
acknowledge that this may result in the transmission provider receiving
penalty revenues on behalf of its native load even when its affiliate
has been identified as offending customers, or vice versa. We
nevertheless believe it is a more equitable and administratively
efficient method for all users of the transmission system that are
subject to unreserved use penalties to be eligible to receive a
[[Page 3042]]
portion of associated revenues. If the Commission were to distinguish
between affiliates and non-affiliates in this instance, it would follow
that transmission customers that are affiliated among themselves, but
not with the transmission provider, should also be excluded from
distributions to the extent one of the customers is offending. Given
the complicated ownership structures prevalent in the electric
industry, in which one company may own a small percentage of several
companies, determining whether certain transmission customers are
affiliates would be a time-consuming exercise for the transmission
provider.
475. As the Commission stated in Order No. 890, we will require all
operational penalty revenues to be distributed, with no exception. In
the case of unreserved use penalties, we require penalty revenues to be
distributed to non-offending customers and, in the case of late study
penalties, we require penalty revenues to be distributed to all non-
affiliates of the transmission provider. We will therefore deny
MidAmerican's request to allow certain thresholds below which
transmission providers may distribute penalty amounts to third parties
such as regional reliability organizations. Such a policy could
decrease the financial incentive built into the current rule, which
rewards non-offending customers with a portion of the distributed
revenues for abiding by Commission policies. We recognize, however,
that it could be administratively difficult for some transmission
providers to distribute small amounts of penalty revenues and note that
transmission providers have flexibility in developing their
distribution methodologies to minimize administrative burdens, by
establishing reasonable minimum thresholds to trigger a distribution,
provided they do not unduly restrict the distribution of penalty
amounts.
c. Applicability of Operational Penalties Proposal to RTOs and Other
Independent or Non-Profit Entities
476. The Commission clarified in Order No. 890 that RTOs and
independent transmission coordinators, like any other transmission
provider, are bound by the requirement to distribute revenues they
receive when they assess operational penalties. The Commission declined
to exempt non-profit transmission providers from the requirement to
distribute unreserved use penalties they pay to the extent they take
service under their own tariffs. If a non-profit transmission provider
incurs an operational penalty as a result of its activities as a
transmission customer, it is required to distribute penalties to non-
offending customers.
Requests for Rehearing and Clarification
477. Ameren asks the Commission to clarify that non-profit
transmission providers, including RTOs, are not liable for any
operational penalties. If a penalty is assessed on an RTO or non-profit
transmission provider, Ameren contends they should not be allowed to
flow through to their ratepayers the costs of such penalties,
regardless of whether their affiliates engage in for-profit activities.
Ameren contends that allowing for such recovery would be inconsistent
with Commission policy.\187\ With respect to RTOs in particular, Ameren
contends that allowing RTOs to pass through penalties essentially
punishes companies for participation in an RTO. To the extent a non-
profit transmission provider is assessed an operational penalty at all,
Ameren contends it should only be obligated to pay such penalty to the
extent it can do so through any operations in which the transmission
provider retains any proceeds above its costs, such as wholesale
marketing operations of the transmission provider or its affiliates. If
the Commission wishes to sanction an RTO, ISO, or independent system
administrator, Ameren argues that it should consider different
measures, such as reductions in management bonuses.
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\187\ Citing Order No. 890 at P 865; Cleco Corp., 104 FERC ]
61,125 at 61,441 (2003).
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478. New York Transmission Owners agree that penalties must be
structured so they do not flow through to other parties and similarly
suggest that penalties be paid through items like variable pay or bonus
programs. With respect to potential penalties paid by NYISO, New York
Transmission Owners ask the Commission to require that they be paid out
of compensation and incentive programs and that the Commission tailor
such penalties to recognize NYISO's limited ability to pay them.
479. NYISO and the ISO/RTO Council, however, object to disallowance
of cost recovery for operational penalties. They state that the
Commission neither generically allowed nor disallowed pass-throughs of
reliability-related penalty costs in Order No. 672 and, instead,
adopted a case-by-case approach, inviting RTOs and ISOs to make filings
under FPA section 205 to propose penalty cost recovery mechanisms. They
argue that the Commission failed to identify any difference between
reliability and operational penalties that would justify departing from
the case-by-case approach adopted in Order No. 672.
480. The ISO/RTO Council argues that use of variable employee bonus
funds to pay operational penalties would penalize employees for issues
beyond their control and impair the ability to hire and retain
qualified management. It contends the Commission would have no
authority under FPA section 316A to impose penalties on particular
employees for tariff violations of their employer utility. The ISO/RTO
Council objects to potential personal liability as a violation of due
process and an attempt to dictate the internal management decisions of
a public utility.
481. NYISO contends that the prohibition on recovering penalty
costs in rates is inconsistent with the Commission's Policy Statement
on Enforcement,\188\ which provides that the level of penalties should
account for the effect on the financial viability of the company that
committed the wrongdoing and reasonably reflect the seriousness of an
offense. NYISO acknowledges that the Commission indicated it would
consider financial impacts on RTOs and ISOs when deciding whether to
assess penalties, but argues the Commission erred in assuming that non-
profit RTOs and ISOs can somehow absorb penalty costs.
---------------------------------------------------------------------------
\188\ Enforcement of Statutes, Orders, Rules, and Regulations,
113 FERC ] 61,068 (2005) (Policy Statement on Enforcement).
---------------------------------------------------------------------------
482. NYISO states that the premise underlying the Commission's
decision in Order No. 890 that RTOs and ISOs have other sources of
revenue that could absorb penalty costs is flatly incorrect. NYISO
explains that it collects revenues for both transmission and non-
transmission services (i.e., market administration) through Rate
Schedule 1 and that all revenues from sources other than Rate Schedule
1 (e.g., interconnection studies, customer trainings, and interest
earnings) are used to reduce Rate Schedule 1 charges. NYISO therefore
contends that it has no excess funds available to pay penalties. NYISO
states that it does interpret Order No. 890 to allow it to recover
penalty costs through any rates and thus questions how a non-profit RTO
and ISO could recover those costs. NYISO asks the Commission to grant
rehearing and allow non-profit RTOs/ISOs to argue, on a case-by-case
basis, for an opportunity to recover penalty costs or to explain why
sanctions other than financial penalties should be imposed.
483. National Grid agrees that the Commission should consider the
unique problems associated with the non-profit
[[Page 3043]]
status of RTOs/ISOs in determining the type and treatment of penalties
applicable to such entities. Absent extraordinary circumstances that
warrant a monetary penalty for RTOs/ISOs, National Grid argues the
Commission should use non-monetary penalties in the first instance to
address violations by the RTO or ISO. To the extent that penalties are
imposed, National Grid contends that the RTO or ISO should be
authorized to pass the costs of such penalties to its customers and
that these customers, in turn should be authorized to recover the costs
of such penalties from their own customers.
Commission Determination
484. The Commission denies rehearing of the decision in Order No.
890 not to categorically exempt any class of transmission providers
from the potential imposition of operational penalties. As we explain
in section III.D.4.a., competing internal policies or staffing issues
could lead an RTO or ISO to treat particular types of requests
differently notwithstanding their organizational independence from
market participants. By imposing late study penalties on RTOs and ISOs,
the Commission has established financial incentives for those
transmission providers to complete request studies in a timely manner
or otherwise justify their inability to do so. RTOs and ISOs are like
any other transmission provider in this regard. We will nonetheless
take into consideration the relative ability of non-profit transmission
providers to pay late study penalties on review of their notification
filings, consistent with the Enforcement Policy Statement.\189\
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\189\ See Policy Statement on Enforcement at P 20 (indicating
that assessment of penalties should take account of the financial
viability of the offender).
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485. We acknowledge, as NYISO points out, that non-profit
transmission providers may not have sources of revenue from which they
can absorb late study penalties other than revenues collected under a
Commission-jurisdictional tariff. As we explain in section III.D.4.a.,
the intent of prohibiting transmission providers from automatically
passing on to customers the costs of late study penalties was to
preclude those transmission providers from designing their rates to
accommodate a pass through of the penalties, i.e., effectively
including penalties in its cost of service. The 60-day due diligence
standard is in place to protect customers and it would therefore be
inappropriate to automatically recover from those customers penalties
assessed for non-compliance. An RTO or ISO is permitted to use revenues
previously collected under Commission-approved rates to pay late study
penalties by reallocating funds as necessary to distribute late study
penalty amounts. This does not mean, as the ISO/RTO Council implies,
that the Commission is imposing personal liability on employees for
penalties applied to an RTO or ISO. Each RTO and ISO has discretion to
determine, as an organization, how to reallocate its funds.
486. We decline to state generically which particular sources of
funds should be used to pay late study penalties, since that question
would best be answered on a case-by-case basis. If the RTO or ISO is
unable to identify any appropriate funds from which to pay a late study
penalty, the Commission will consider case-specific cost-recovery
proposals under FPA section 205, provided they do not allow for
automatic pass-through of penalties applied to the RTO or ISO.
5. ``Higher of'' Pricing Policy
487. In Order No. 890, the Commission did not address proposals to
change or clarify the ``higher of'' pricing policy and, instead,
addressed only the narrow issue of whether changes to the pro forma
OATT are necessary to ensure that, consistent with the ``higher of''
policy, incremental cost transmission rates are presented as monthly
rates for service.\190\ Rather than quoting incremental costs as
monthly rates, the Commission noted that some transmission providers
had been quoting incremental rates as lump sum payments, a practice
that is inconsistent with our ratemaking policy. In Order No. 890, the
Commission concluded that changes to the pro forma OATT are not needed
to address this matter. The Commission explained that the transmission
provider must continue to include a proposed monthly incremental rate
with its offer of service whenever it proposes to charge the customer
an incremental rate. The transmission provider must also provide cost
support for the derivation of the rate consistent with the cost support
that the transmission provider would provide to the Commission in a
section 205 rate filing.
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\190\ Order No. 890 at P 884. In Order No. 888, the Commission
stated that system expansions should be priced at the higher of the
embedded cost rate (including the expansion costs) or the
incremental cost rate, consistent with the Transmission Pricing
Policy Statement. See Inquiry Concerning the Commission's Pricing
Policy for Transmission Services Provided by Public Utilities Under
the Federal Power Act, Policy Statement, 59 FR 55031 at 55037 (Nov.
3, 1994), FERC Stats. & Regs. ] 31,005 at 31,146 (1994), order on
reconsideration, 71 FERC ] 61,195 (1995) (Transmission Pricing
Policy Statement).
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Requests for Rehearing and Clarification
488. EEI requests clarification that transmission providers may
calculate the incremental costs of network upgrades so as to allow
incremental rates to vary over the term of the contract to reflect
changes in the transmission provider's cost of service. While
recognizing that the Commission declined to grant this clarification in
Order No. 890, EEI believes that this clarification will enhance
compliance with the Commission's policies and is therefore within the
scope of this proceeding.
489. Great Northern seeks rehearing of the Commission's decision
not to require transmission providers to permit a customer to opt for a
longer contract term (to obtain a longer amortization period and a
lower rate) once the incremental cost of transmission upgrades has been
determined. Great Northern argues that failure to grant this option
will result in uncertainty and delay in the development of competitive
generation resources. Great Northern claims that there is no record
evidence that adopting its request would be problematic for any
transmission provider, customer, or market participant. Great Northern
contends that, if an increase in contract term would trigger a need for
additional, or different, upgrades, it would be the responsibility of
the transmission customer to pay for those upgrades over the term of
the contract.
490. If the Commission does not allow general flexibility for
transmission customers to adjust the term of their requested
transmission service contract to provide a longer period for amortizing
the costs of system upgrades once the incremental cost of expansion is
disclosed by the transmission provider, Great Northern requests the
Commission to allow contracts to be extended in the specific
circumstances where pending transmission service requests were made for
one year (or longer if necessary to pay for any required system
upgrades) and the transmission provider is on notice of the potential
need for a longer contract term. Great Northern states that it has made
twenty-three transmission service requests on transmission provider
systems which are currently being studied, and in each instance the
request was made for a one year term or longer if necessary to pay for
any required system upgrades.
[[Page 3044]]
Commission Determination
491. We continue to believe that the specific pricing proposal
suggested by EEI is outside the scope of this proceeding, as the NOPR
and Order No. 890 addressed only the narrow issue of whether changes to
the pro forma OATT are necessary to ensure that incremental cost
transmission rates are presented as monthly rates for service. As the
Commission explained in Order No. 890, such issues are best addressed
on a case-by-case basis in particular rate proceedings. We note,
however, that the capital costs of upgrades, as estimated in a
facilities study, and eventually specified in a service agreement
through an incremental rate, are not subject to change once the
customer has executed the service agreement. It would not be
appropriate to vary capital costs over the term of such contracts.
492. Great Northern presents no new arguments or information on
rehearing that cause us to revisit the decision not to require the
transmission provider to permit the customer to opt for a longer
contract term once the incremental cost of the upgrades has been
determined. The Commission explained in Order No. 890 that the specific
upgrades required to provide the requested transmission service may
depend on the time period over which the service is provided. Allowing
the customer to opt for a longer contract term may therefore trigger a
need for additional, or different, upgrades. If this were to happen,
there would be disruption of the study process and costs could
increase.
493. Additionally, such changes could undermine the fundamental
first-come, first-served aspect of long-term transmission service.
Order No. 888 provided for long-term firm point-to-point transmission
service on a first-come, first-served basis.\191\ Lengthening the term
of a contract once the incremental costs of upgrades is determined
would be a material change to the original transmission service
request, voiding the original request and creating a new request.
Allowing a customer to lengthen its contract term as Great Northern
suggests could allow the transmission customer to supersede another
eligible customer's first-in-time claim to future transmission service
in violation of Order No. 888. The fact that the transmission customer
would be responsible for paying for any additional upgrades, or the
possibility that development of competitive generation could be
delayed, does not address the potential uncertainty and chaos that
could arise from undermining the first-come, first-served foundation of
long-term point-to-point transmission service. We therefore deny
rehearing on this issue.
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\191\ See pro forma OATT section 13.2.
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6. Other Ancillary Services
a. Demand Response
494. The Commission affirmed in Order No. 890 the existing pro
forma OATT provision that transmission customers may purchase from
third parties, or make alternative comparable arrangements for the
provision of all ancillary services except for scheduling, system
control and dispatch service, and reactive supply and voltage control
service. Regarding the sale of other ancillary services, the Commission
clarified that the sale of such services by load resources should be
permitted where appropriate on a comparable basis to service provided
by generation resources. The Commission modified Schedules 2, 3, 4, 5,
6, and 9 of the pro forma OATT to make clear that reactive supply and
voltage control, regulation and frequency response, energy imbalance,
spinning reserves, supplemental reserves and generator imbalance
services, respectively, may be provided by non-generation resources
such as demand resources where appropriate.
Requests for Rehearing and Clarification
495. E.ON U.S. asks the Commission to clarify on rehearing that,
for purposes of providing reactive supply and voltage control service,
non-generation resources only include dynamic resources. Without such a
clarification, E.ON U.S. contends that capacitors added in big blocks
could claim to be resources capable of providing reactive power, even
though such resources only supply VARS and would need to be properly
sized and located in order to provide effective reactive capability.
E.ON U.S. also argues that ``non-generation sources'' must be a
controllable resource, i.e., a resource that a transmission provider
can connect to via an automatic signal, to be followed automatically
and immediately by the resource within a time period that is useful for
providing reactive power.
496. E.ON U.S. requests further clarification that, for regulation
and frequency response service, the non-generation resource must be
able to match and follow the corresponding generation resource provider
instantaneously, in the same manner that generation resources now
provide this service for load. If the non-generation resource does not
have this capability, E.ON U.S. contends that the transmission system
could be placed in jeopardy and the transmission provider could be
subject to potential reliability penalties.
497. Southern asks the Commission to confirm that demand response
resources should satisfy the same reliability criteria for providing
ancillary services as are required of generation resources.
Specifically, Southern argues that such resources must meet regional
reliability council requirements and, if no such requirements have been
formalized, balancing authority requirements for the qualification of
such resources, so long as those qualification requirements are not
unduly discriminatory. Southern contends the Commission's focus in
Order No. 890 on the capability of demand resources to provide
ancillary services may not take into consideration qualification of
those resources under non-discriminatory, reliability-based criteria.
498. Southern also notes that transmission providers have a certain
degree of discretion, within the bounds of applicable criteria, to
determine the quantity, mix and distribution of resources held to
provide various system reliability functions. Southern states, for
example, that it holds and maintains reserves from the lowest-cost
resources available for that purpose. Southern requests clarification
that transmission providers are under no obligation to purchase from
non-generation resources on a non-economic basis relative to otherwise
comparable generation resources or to somehow discriminate in favor of
non-generation based resources.
Commission Determination
499. The Commission affirms the decision in Order No. 890 that the
sale of ancillary services by load resources should be permitted where
appropriate on a comparable basis to service provided by generation
resources. A transmission provider may impose appropriate technical
criteria, comparable to the requirements placed on generation
resources, in order to reliably allow load resources to provide the
different ancillary services. We note that such criteria and
requirements have been implemented in RTO markets that allow demand
response to participate as an ancillary service resource.\192\ As
[[Page 3045]]
Southern suggests, any such reliability-based qualification criteria
should be developed and imposed on a non-discriminatory basis. We also
agree with Southern that transmission providers should give comparable,
not preferential, consideration of load resources in selecting the mix
of resources to supply ancillary services.
b. Pricing and Procurement of Reactive Power
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\192\ PJM, for example, allows load resources to provide
regulation service, but requires telemetering ability and pre-
certification to show the resource can meet the physical
characteristics in order for the resource to qualify. To participate
in the synchronized reserve market in PJM, demand response resources
must install infrastructure such that they can curtail consumption
within ten minutes and also must provide metering information needed
to account for their response.
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500. The Commission rejected requests to modify requirements
regarding the provision and pricing of reactive power. The Commission
reiterated the policy stated in Order No. 2003, et al., that
interconnection customers must be treated comparably with the
transmission provider and its affiliates in terms of reactive power
compensation.\193\ If the transmission provider pays its own generators
or those of its affiliates for reactive power, then the transmission
provider also should pay interconnecting generators for providing
reactive power within the specified range.\194\ The Commission stated
that it would continue to resolve compensation issues for reactive
power to qualifying generators on a case-by-case basis.
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\193\ See Standardization of Generator Interconnection
Agreements and Procedures, Order No. 2003, 68 FR 49845 (Aug. 19,
2003), FERC Stats. & Regs. ] 31,146 (2003), order on reh'g, Order
No. 2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ]
31,160 (2004), order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4,
2005), FERC Stats. & Regs. ] 31,171 (2004), order on reh'g, Order
No. 2003-C, 70 FR 37,661 (Jun. 30, 2005), FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. National Association of Regulatory
Utility Commissioners v. FERC, No. 04-1148, 2007 U.S. App. LEXIS 626
(D.C. Cir. Jan. 12, 2007).
\194\ Citing Order No. 2003-B at P 119.
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Requests for Rehearing and Clarification
501. E.ON U.S. requests that the Commission commence a separate
rulemaking to address the conflicts that continue to arise regarding
reactive power. E.ON U.S. argues that the Commission should provide the
proper incentives for locating resources to provide the maximum benefit
in terms of reactive power, and that consumers should not be forced to
pay for reactive power for units that provide no benefit in terms of
reactive capability. E.ON U.S. contends it is inappropriate to
compensate units for reactive power unless they are built in a location
where reactive power output is desirable from an engineering standpoint
and are available in the time period needed in order to be useful to
the system. E.ON U.S. contends that initiating a rulemaking to consider
the locational requirements for reactive power payments would ensure a
good supply of reactive power and reduce the amount of time-consuming
and wasteful litigation.
Commission Determination
502. We again decline the request to initiate a separate rulemaking
process to address issues regarding compensation for reactive power.
The Commission does not believe that acting generically on pricing for
reactive power is necessary at this time. As the Commission explained
in Order No. 890, we will continue to resolve compensation issues for
reactive power to qualifying generators on a case-by-case basis.\195\
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\195\ See Order No. 890 at P 898.
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c. Operating Reserves
Requests for Rehearing and Clarification
503. Sempra Global contends that the Commission failed to address
its comments requesting clarification that transmission providers are
obligated to offer and make available operating reserves to a generator
located within the transmission provider's control area, even if the
generator-customer is serving load outside of the transmission
provider's control area. Sempra Global states that various transmission
providers within the WECC interpret the requirement to provide
operating reserves to customers serving load within the control area
differently. Sempra Global explains that some in the WECC have argued
that power cannot be sold as firm unless it includes operating reserves
and that the current calculation of operating reserve requirements for
WECC control area operators includes a netting of firm imports and
exports.
504. As a result, Sempra Global argues that transmission providers
that operate control areas are able to effectively shift portions of
their operating reserve requirements by contracting for firm power from
other control areas, provided that the selling control area carries
additional operating reserves for the sale. Sempra Global contends that
this limits the abilities of generators to make firm power sales to
entities outside the control area in which the generator is located.
Sempra Global also argues that this practice allows the transmission
provider to thwart competition from non-utility generators by limiting
the ability of merchant generators to make firm power sales outside of
the control area. Sempra Global asks the Commission to clarify that
transmission providers are obligated to offer and make available
operating reserves regardless of where the merchant generation-customer
is serving load.
Commission Determination
505. We disagree with Sempra Global that the transmission provider
should be obligated to offer and make available operating reserves
under Schedules 5 and 6 of the pro forma OATT when transmission service
is used to serve load outside the transmission provider's control area.
Operating reserves are needed to serve load within the control area in
the event of system contingencies. Unless alternative arrangements are
made, the transmission provider provides these reserves from its own
resources. It would be inappropriate to require the transmission
provider to use its resources to provide additional operating reserves
to loads in other control areas because the transmission providers in
those control areas are under their own obligation to make operating
reserves available.
506. We therefore conclude that the existing requirements of the
pro forma OATT are sufficient to ensure that operating reserves are
available to serve the type of transaction discussed by Sempra Global.
A generator serving load outside the control area can make alternative
comparable arrangements to provide reserves on behalf of its load by
contracting with third parties. The generator could also request, as
part of its negotiation with a customer, that the customer acquire
reserves from its transmission provider as necessary to support the
transaction. Modification of the pro forma OATT is not necessary to
enable generators to engage in firm power sales to loads outside of
their control area.
D. Non-Rate Terms and Conditions
1. Modifications to Long-Term Firm Point-to-Point Service
507. In Order No. 890, the Commission concluded that the methods
for evaluating requests for long-term point-to-point transmission
service may not be comparable to the manner in which transmission
service is planned for bundled retail native load and, therefore, may
no longer be just, reasonable and not unduly discriminatory. To remedy
this potential for undue discrimination, the Commission amended the pro
forma OATT to require transmission providers, other than most RTOs and
ISOs, to offer a modified form of planning redispatch as well as a
conditional firm option to long-term point-to-point customers. A number
of
[[Page 3046]]
petitioners have requested rehearing of the Commission's decision to
modify the planning redispatch requirements and institute a new
obligation to offer the conditional firm option. We first address the
threshold requirement to offer these options and then turn to
implementation of each option.
a. Requirement To Offer Planning Redispatch and Conditional Firm
508. The requirement to offer planning redispatch was adopted in
Order No. 888 under section 19.3 of the pro forma OATT. Transmission
providers were required to identify, in each system impact study,
system constraints as well as redispatch options available to resolve
those constraints and provide planning redispatch to the extent
redispatch was more economical than the cost of transmission upgrades.
In Order No. 890, the Commission modified the planning redispatch
requirement, adding specificity to the information required in the
system impact study and limiting planning redispatch to an option that
is reassessed every two years if the customer chooses not to pay for
upgrades. The Commission also removed the limitation of offering
planning redispatch only when it is more economical than the cost of
transmission upgrades. The Commission rejected arguments against the
underlying requirement to offer planning redispatch as collateral
attacks on Order No. 888.
509. The Commission also found that transmission providers were
using a service analogous to the conditional firm option, in addition
to planning redispatch, to serve their own loads. The Commission
concluded that transmission providers must evaluate transmission
availability to serve long-term firm point-to-point service requests in
a manner that is comparable with the method used to evaluate their own
transmission needs and to integrate their resources to serve bundled
retail native load. The Commission therefore required non-ISO/RTO
transmission providers to make available both the planning redispatch
and conditional firm options to long-term firm point-to-point
customers. The Commission emphasized, however, that transmission
providers are not required to offer either the planning redispatch or
conditional firm option if doing so would impair the transmission
provider's ability to reliably serve other firm customers, including
native load and network customers.
510. The Commission also placed several limitations on the nature
of the planning redispatch and conditional firm options to limit the
their potential impact on reliability. First, the Commission required
that the planning redispatch and conditional firm options be made
available to long-term point-to-point customers. While a transmission
provider might choose to propose planning redispatch or conditional
firm on a shorter-term basis, it would not be required to under the pro
forma OATT. Second, the Commission distinguished between two different
types of customers that may request the service: customers who support
the construction of upgrades and those who do not. For customers
supporting the construction of upgrades, the planning redispatch or
conditional firm options need only be offered until the time when the
upgrades are constructed. The conditions or redispatch applicable to
the interim period must be specified in the service agreement and will
not be subject to change. For customers choosing not to support the
construction of new facilities, the planning redispatch or conditional
firm options must be made available as a reassessment product, i.e.,
subject to reassessment every two years by the transmission provider.
Every two years, or sooner if at the continuation of the term of
service, the transmission provider must reassess the redispatch
required to keep the service firm or the conditions or hours under
which the transmission provider may conditionally curtail the
service.\196\
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\196\ The Commission acknowledged that some transmission
providers may be able to provide conditional firm service over a
period longer than two years without the need for reassessment. In
the event a transmission provider is able to extend the assessment
period, the Commission stated that waiver or extension of the right
to reassess the availability of the option would be permitted,
provided that the waiver or extension is provided consistently for
all similarly situated service.
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511. With regard to transmission service provided by RTOs and ISOs,
the Commission found that it would be inappropriate to require RTOs and
ISOs with real-time energy markets to adopt the provisions for
conditional firm point-to-point service. The Commission explained that
customers transacting in RTOs and ISOs are able to buy through
transmission congestion in the real-time energy markets and need no
prior reservation in order to access transmission. The Commission did
require, however, RTOs and ISOs that already provided planning
redispatch pursuant to section 13.5 of the Order No. 888 pro forma OATT
to modify the relevant provisions of their tariffs consistent with the
directives of Order No. 890.\197\ RTOs and ISOs not already providing
planning redispatch were not required to amend their tariffs to include
the planning redispatch option.
---------------------------------------------------------------------------
\197\ The Commission explained such modification would include
the transmission provider's obligation to post monthly redispatch
costs for each transmission facility over which planning and
reliability redispatch are provided.
---------------------------------------------------------------------------
512. The Commission declined to adopt the conditional firm option
for network service and made no changes to the planning redispatch
provisions for network customers.
(1) Planning Redispatch
Requests for Rehearing and Clarification
513. Several petitioners object to the requirement that
transmission providers offer planning redispatch point-to-point
service.\198\ They argue that the planning redispatch requirement can
degrade the quality of service to existing firm customers by increasing
loop flow and creating reliability problems or by shifting costs to
them. They argue that planning redispatch increases curtailment risks
to existing customers because generators are used in a manner that is
different than the planned use of those generators. Ameren argues that
planning redispatch is unduly discriminatory in that it requires the
use of the transmission provider's generation resources but not the
resources of network customers or third parties. Ameren also argues
that planning redispatch is not superior to the options already in
place in the pro forma OATT adopted in Order No. 888. Other petitioners
assert that the modifications to planning redispatch will remove
incentives for transmission expansion because planning redispatch will
always be cheaper and easier for customers than paying for new
transmission capacity.\199\
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\198\ E.g., Ameren, NRECA, and TDU Systems.
\199\ E.g., E.ON LSE, NRECA, and TDU Systems.
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514. Several petitioners argue that the merits of commenter
arguments on planning redispatch should be addressed rather than
rejected as collateral attacks against Order No. 888.\200\ Ameren asks
the Commission to revisit the requirement imposed in Order No. 888 to
provide planning redispatch to point-to-point customers as the
Commission revisited all Order No. 888 requirements in Order No. 890.
E.ON LSE asserts that arguments about the reliability impacts of the
planning redispatch service are not barred as collateral attacks
because the Commission changed the service by removing the expansion
price cap. E.ON LSE states that by removing the expansion cap the
Commission placed a burden on transmission providers to provide
planning redispatch even if it
[[Page 3047]]
would be more costly than the construction of transmission upgrades.
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\200\ E.g., Ameren, E.ON LSE, and Southern.
---------------------------------------------------------------------------
515. Ameren and Southern reiterate concerns that modeling of
planning redispatch will be challenging given the difficulty of
projecting redispatch costs and the availability of generating units,
even if the projections are limited to a two-year period. Ameren
expects that it may deny service on reliability grounds for every
request. Given this expectation, Ameren argues that the Commission
should develop clear reliability guidelines so that transmission
providers can comply without subjecting themselves to claims of
discrimination for denying service. E.ON LSE states that projecting
redispatch costs will be difficult and likely result in inaccurate
estimates.
516. Other petitioners express concern that a transmission provider
may avoid its obligation to provide planning redispatch or conditional
firm service by rejecting requests based on an arbitrary, unreasonable
and conservative definition of reliability.\201\ Constellation states
that oversight is necessary to ensure that transmission provider
conclusions are sufficient to demonstrate that planning redispatch
options were properly considered. EPSA supports publicly posting on
OASIS reserve margin measures to eliminate the inflation of margins
exceeding reliability requirements. Williams recommends adoption of a
reliability standard to ensure the options are not improperly rejected
on reliability grounds.
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\201\ E.g., Constellation, EPSA, and Williams.
---------------------------------------------------------------------------
517. Ameren argues that the Commission should grant a blanket
exemption from the planning redispatch requirement for all RTOs
because: RTO markets are independent; RTOs do not own or operate
generation; and the redispatch requirement could exacerbate seams
issues and affect the calculation and distribution of financial
transmission rights (FTRs). Ameren expresses concern that the planning
redispatch requirement will also adversely impact the calculation of
the revenue sufficiency guarantee charges in MISO.
518. Several petitioners contend that the obligation to provide the
planning redispatch option contradicts section 217 of the FPA to the
extent it impinges on native load service.\202\ South Carolina E&G
argues that requiring transmission providers to offer planning
redispatch could marginalize native load, in violation of section 217,
unless the Commission modifies section 13.6 of the pro forma OATT to
eliminate comparable curtailment of native load and non-native load
service. South Carolina E&G contends that the Commission is precluded
under section 217(k) from making a finding that it is unduly
discriminatory if practices governing the evaluation of long-term firm
point-to-point service are not comparable to the manner in which
transmission service is planned for bundled retail native load. South
Carolina E&G contends that recognition of the curtailment primacy of
native load service would provide a necessary escape mechanism should
the planning redispatch or conditional firm options threaten native
load service. South Carolina Regulatory Staff objects to the planning
redispatch and conditional firm options to the extent that native load
purchasers of electricity are required to bear the costs of additional
transmission capacity necessitated by transmission to non-native
consumers.
---------------------------------------------------------------------------
\202\ E.g., E.ON LSE, South Carolina E&G, South Carolina
Regulatory Staff, and Southern.
---------------------------------------------------------------------------
519. E.ON LSE also argues that FPA section 217 prohibits requiring
transmission providers to offer native load redispatch to non-native
load customers on the basis of claimed discrimination. E.ON LSE asks
the Commission to clarify that, in real time, LSEs may use all or a
portion of their resources to serve native load rather than redispatch
for third parties. E.ON LSE also requests clarification that the
generation facilities having restricted run times may be reserved for
the use of native load needs and not be offered for firm point-to-point
planning redispatch service.
520. NorthWestern requests that the Commission grant waiver of the
redispatch requirements for transmission providers who do not have the
ability to dispatch generation. Washington IOUs request Commission
clarification that when a viable, parallel path is available to a
transmission customer to move its power, the transmission provider is
not required to offer planning redispatch service. Washington IOUs
state that in the Pacific Northwest transmission customers may be able
to move power to the same point more easily by purchasing transmission
service over a neighboring transmission system. Washington IOUs argue
that in such a situation requiring a jurisdictional utility to offer
planning redispatch service would unreasonably increase the costs of
providing transmission service.
521. Washington IOUs further argue that the Commission erred in not
exempting hydro-based systems from the planning redispatch
requirements. Washington IOUs argue that the Commission failed to
recognize that hydro units may not be available due to recreational,
flood control, fish mitigation and other non-power related
requirements. Washington IOUs further assert the Commission should
exempt hydro-based systems from providing planning redispatch because
of possible occurrence of pricing disputes, under-recovery of costs,
and disputes over study of planning redispatch opportunities.
522. TAPS asserts that the Commission failed to revise to insert
new planning redispatch provisions into pro forma OATT section 32.3
pertaining to network service system impact studies. TAPS also argues
that the Commission must ensure that transmission service provided to
network customers is comparable to the service transmission providers
provide themselves through planning redispatch and low granularity
system models. TAPS argues that transmission providers use planning
redispatch combined with their system-wide modeling to designate
network resources that otherwise might be undeliverable. TAPS asserts
they do this by treating their control areas as a whole for sink
purposes while selectively disaggregating their resources for sourcing
purposes. TAPS asserts that undue discrimination arises because a
network customer's request to bring on new network resources is modeled
with granularity, without the benefit of planning redispatch and the
redispatch assumed by modeling the transmission provider's own load as
a single system sink when designating resources. TAPS asks the
Commission to redress this discrimination by prohibiting the
transmission provider from denying any request for transmission to a
network customer, or requiring upgrades or mitigation, the costs of
which are not shared on a load-ratio basis, if the request would have
been accepted if the transmission provider's own load had been the
designated sink.
523. Finally, EEI requests clarification of the length of the
service request that would qualify for these options. EEI notes that
sections 15.4(b) of the pro forma OATT does not qualify the provision
of planning redispatch only to long-term firm point-to-point customers.
EEI asks the Commission to amend sections 15.4(b) of the pro forma OATT
to make this section consistent with the statements in Order No. 890
providing that a transmission provider is obligated to provide planning
redispatch service to customers requesting long-term firm point-to-
point service, but not to customers requesting short-term firm service.
[[Page 3048]]
Commission Determination
524. The Commission affirms the decision in Order No. 890,
originally established in Order No. 888, to require transmission
providers to redispatch their generation resources in certain
circumstances to create additional capacity on the transmission grid.
Petitioners arguing for removal of this requirement have failed to show
any actual degradation of reliability, degradation of service to other
firm customers, or delay in grid expansion caused by planning
redispatch service during the first 10 years in which the requirement
was in place. We therefore decline to eliminate this long-standing
option for point-to-point customers.\203\
---------------------------------------------------------------------------
\203\ Arguments that the Commission has no authority to impose a
planning redispatch obligation are a collateral attack on Order No.
888. We disagree with E.ON LSE's assertion that removal of the
expansion cap placed a new burden on transmission providers by
fundamentally changing the nature of the service. While Order No.
890 required planning redispatch to be provided even when it is more
expensive than transmission upgrades, service is only guaranteed for
two years if customers do not pay for upgrades. This puts a bound
upon the service for transmission providers that benefits rather
than burdens them.
---------------------------------------------------------------------------
525. We also affirm the limitation placed on the planning
redispatch requirement, which we believe adequately address
petitioners' concerns regarding potential effects on reliability or
service quality. The Commission in Order No. 890 scaled back the
obligation to provide planning redispatch service by severing the link
between it and transmission upgrades, no longer requiring the provision
of planning redispatch for an indefinite period.\204\ Under the
modified planning redispatch option, transmission customers must agree
to pay for transmission upgrades or agree to have the conditions of
their planning redispatch service reassessed every two years. These
modifications more appropriately balance customers' needs with
transmission providers' reliability and native load obligations.
Planning redispatch service under Order No. 890 is, therefore, superior
to that service under Order No. 888, contrary to Ameren's assertions.
---------------------------------------------------------------------------
\204\ Order No. 890 at P 926.
---------------------------------------------------------------------------
526. We disagree that planning redispatch will remove incentives
for transmission expansion. As modified in Order No. 890, planning
redispatch may provide a means for greater transmission investment as
customers will be able to receive the bridge service prior to the
completion of upgrades. The benefit of immediate access to the
transmission grid could result in more attractive financing and cash
flow options for new resources, in turn resulting in more investment in
transmission. Moreover, customers taking the reassessment product may
identify over time others willing to jointly fund upgrades, leading to
further investment. In asserting a negative impact on transmission
expansion, petitioners imply that planning redispatch will always be a
less expensive option than investment in upgrades. But if that were
true then planning redispatch would have proliferated over the last 10
years given that transmission providers were obligated to provide
planning redispatch if it was more economical than transmission
upgrades.
527. Petitioners' concerns about harms to existing customers
through increases in loop flow and curtailment risks are not unique to
rights granted through the use of planning redispatch. The efficient
use of the existing transmission grid, including every incremental new
firm use, brings with it an increased risk in the instances and
megawatt quantity of curtailment for all existing users of the grid. As
the Commission explained in Order No. 890, the modifications to
planning redispatch will enable transmission providers to better manage
the risks of curtailment for current users of the transmission grid
because the obligation to redispatch will no longer be open-ended.\205\
We reject TDU Systems' assertion that planning redispatch will increase
costs for network customers because it is based upon an incorrect
assumption that Order No. 890 would require transmission providers to
redispatch network customers' resources for point-to-point
customers.\206\
---------------------------------------------------------------------------
\205\ See id. at P 593.
\206\ TDU Systems cites to an argument made by NRECA that
concerns the transparent dispatch advocates' proposal for inclusive
bid-based real-time redispatch. NRECA Supplemental, Affidavit at 27.
---------------------------------------------------------------------------
528. We disagree with NRECA and TDU Systems that planning
redispatch service increases curtailment risk because generation is
used differently than planned. By definition, transmission providers
must study the resources that they will redispatch in order to offer
each individual planning redispatch service. Thus, generation will be
used by transmission providers as planned. While we acknowledge that
planning redispatch service presents complicated modeling issues, even
when limited to a two-year period, modeling difficulties exist
throughout the utility industry. If anything, the modifications to the
planning redispatch option adopted in Order No. 890 lessen the modeling
burden by scaling back the planning redispatch requirement.
529. With regard to loop flows, we agree with NRECA that changing
and unpredictable loop flows make it more difficult for system
operators to understand their systems and respond to contingencies
properly. We do not agree, however, that planning redispatch will have
any greater adverse effect on loop flows than the addition of a new
generator to the grid or the addition of or a change to a firm point-
to-point use. The effects of planning redispatch service will be
studied in a system impact study well before the service is provided,
like any other proposed firm use of the system. Transmission providers
will therefore be able to adjust to planning redispatch uses of the
system in the same way they now adjust to additions of generation and
all new or changed firm point-to-point uses.
530. Planning redispatch service does not unduly discriminate
against transmission providers by requiring them to use their resources
to provide service. The Commission does not require the use of network
customer and third party resources to provide planning redispatch
point-to-point service because third parties and network customers do
not provide the associated transmission service. Third parties or
network customers that create additional grid capacity by
redispatching, such as through a transaction that flows counter to the
majority of flows on a line, cannot sell the additional transmission
capacity that they create. A transmission provider using its resources
to serve loads on its system can however create and sell additional
transmission capacity on its system through control of those resources.
It is therefore not unduly discriminatory to require the use of
transmission provider resources to provide planning redispatch to long-
term point-to-point customers.
531. We decline to develop reliability guidelines or standards for
implementing planning redispatch. The underlying obligation to provide
planning redispatch has been in place for 10 years without such
guidelines. This is not surprising given that each transmission system
is different and any industry-wide guidelines would necessarily be
over- or under-inclusive. Transmission providers must already comply
with those reliability standards approved by the Commission and we will
not unnecessarily layer additional standards upon the transmission
providers for planning redispatch or conditional firm service.
Transmission providers should retain responsibility for incorporating
reasonable
[[Page 3049]]
assumptions into their models in order to manage risks.
532. We do, however, clarify herein additional valid reasons for
denying service on reliability grounds. We will not require publication
of the metrics underlying these reliability grounds or, as EPSA
requests, identification of reserves set aside for customers; these
metrics likely contain competitive information or relate to state-
imposed requirements. If eligible customers believe they have been
unreasonably denied redispatch or conditional firm service on
reliability grounds, they should bring the matter to the Commission's
attention through a complaint or other appropriate procedural
mechanism. Transmission providers can proactively address claims of
discrimination resulting from denials of planning redispatch (or
conditional firm) service by publishing modeling assumptions and free
flow of information between the transmission provider and potential
customers.\207\
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\207\ We note that increased information regarding the modeling,
data, and assumptions used by the transmission provider to calculate
ATC and plan the system must now be made available under Attachments
C and K to the pro forma OATT.
---------------------------------------------------------------------------
533. Concerns about a transmission provider's inability to project
redispatch costs are misplaced. In Order No. 890, the Commission
directed transmission providers to provide eligible customers with non-
binding estimates of the incremental costs of redispatch.\208\ The
Commission expects that transmission providers will use due diligence
in providing the costs estimates, but as with any non-binding estimate
they will not be liable for their inability to accurately predict
future costs.
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\208\ Order No. 890 at P 958.
---------------------------------------------------------------------------
534. The Commission grants rehearing of the decision to require
RTOs and ISOs to modify planning redispatch provisions that remain in
their tariffs. The tariffs of many RTOs and ISOs were developed to
layer energy markets and financial transmission rights on top of the
existing pro forma OATT physical rights systems. Upon consideration of
petitioner's arguments, we conclude it is more appropriate not to
disturb these developments by requiring changes to the existing
planning redispatch provisions stated in sections 13.5, 15.4, 19.1 and
19.3 of the pro forma OATT.\209\
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\209\ To the extent an RTO or ISO has already incorporated this
new language into its OATT in a prior compliance filing, removal of
that language is at the RTO's or ISO's discretion.
---------------------------------------------------------------------------
535. We will not, however, grant RTOs and ISOs a blanket exemption
from the planning redispatch requirement, as requested by Ameren. RTOs
and ISOs that currently offer planning redispatch in addition to the
redispatch offered through their energy markets prior to issuance of
Order No. 890 must continue to provide that service.\210\ Where such
service is offered, customers should not be excluded from accessing the
service through planning redispatch unless the Commission has
previously found or finds in the future that such exclusion is
consistent with or superior to the provisions of the pro forma OATT.
The exacerbation of seams issues and disruption of FTR processes are
issues that we would consider if an RTO or ISO seeks to terminate its
existing planning redispatch service.\211\
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\210\ For example, although SPP does not own generation,
transmission owners within SPP retain the obligation through SPP's
Attachment K to use their resources to provide planning redispatch
for firm transmission service. See Southwest Power Pool FERC
Electric Tariff Fifth Revised Volume No. 1, Attachment K, section B,
Original Sheet No. 238-239 (Effective February 1, 2007).
\211\ Ameren's concern with disruption of MISO's revenue
sufficiency guarantee and FTR allocation processes due to
implementation of the planning redispatch requirement is misplaced.
Under MISO's tariff, the provisions of Module C (Energy Markets,
Scheduling and Congestion Management) or the ITC Rate Schedule apply
if redispatch is more economical than constructing transmission
upgrades. See Midwest ISO Transmission and Energy Markets Tariff,
section 13.5. MISO need not change its tariff provisions for the
management of redispatch through its energy markets because the
Commission has already accepted them as consistent with or superior
to the Order No. 888 pro forma OATT.
---------------------------------------------------------------------------
536. We also decline to provide a blanket exemption from the
planning redispatch requirement for transmission providers without
generation or the ability to dispatch generation. We clarify, however,
that transmission providers without the ability to dispatch generation
cannot reliably provide planning redispatch service and have no
obligation to procure generation to provide the service. We deny a
blanket exemption because transmission providers' situations can change
over time so that they gain the ability to dispatch generation.
537. We affirm our decision to not generically exempt
hydroelectric-based systems from the provision of planning redispatch
service. Contrary to Washington IOU's assertion, the Commission took
into consideration the fact that hydroelectric units may not be
available due to recreation, flood control or fish mitigation when it
acknowledged the ``added difficulty of predicting water availability''
in hydroelectric systems.\212\ While there is potential for disputes
regarding the availability and cost of a hydroelectric unit, such
disputes are not unusual for other types of units that are equally
subject to the planning redispatch requirements.
---------------------------------------------------------------------------
\212\ Order No. 890 at P 948.
---------------------------------------------------------------------------
538. We disagree that the availability of firm transmission service
over a parallel path on another transmission provider's system should
relieve a transmission provider of the obligation to provide planning
redispatch. In order to obtain planning redispatch service, a customer
must agree to and pay for a system impact study, await the results of
the study and sign a non-conforming transmission service agreement. We
would not expect a customer to undertake the more complicated process
of obtaining planning redispatch if the transmission service meeting
the customer's needs is available elsewhere. We therefore see no need
to limit the availability of planning redispatch service as Washington
IOUs request.
539. It is not necessary to amend the curtailment priorities under
the pro forma OATT in order for the planning redispatch requirement to
be consistent with FPA section 217, as South Carolina E&G contends. As
we explain in section II.B, section 217(b) provides certain protections
to a specified class of utilities using their firm transmission rights,
to the extent required to meet their service obligations. The provision
of planning redispatch does not impair the use of those firm
transmission rights, or otherwise marginalize native load,
notwithstanding the curtailment priorities established in section 13.6
of the pro forma OATT. As the Commission explained in Order No. 890,
there is no obligation to offer planning redispatch if it either (i)
degrades or impairs the reliability of service to native load
customers, network customers and other transmission customers taking
firm point-to-point service or (ii) interferes with the transmission
provider's ability to meet prior firm contractual commitments to
others. We clarify that this exempts transmission providers from
providing planning redispatch from resources that are expected to
provide reliability redispatch in response to constraints. Further, if
resources with restricted run times are required to meet the reliable
service needs of native load, including reliability redispatch needs,
these resources need not be offered for planning redispatch service.
The obligation to offer planning redispatch is therefore consistent
with the requirements of section 217.
540. Contrary to South Carolina Regulatory Staff's assertions,
native load will not bear the costs of additional transmission capacity
created through either the planning redispatch or conditional firm
options. While the
[[Page 3050]]
options could lead to the construction of more transmission if
customers agree to pay for transmission upgrades, during the period
these services are provided they do not require the construction of
transmission upgrades. Rather, they are provided by curtailing the
customer or redispatching the transmission provider's resources to
create long-term firm transmission. Moreover, costs otherwise recovered
from native load customers are reduced by the additional revenues
gained by the additional sales of conditional firm and planning
redispatch service.
541. We also disagree that FPA section 217(k) precludes the
Commission from finding that it is unduly discriminatory for
transmission providers to engage in planning redispatch to serve native
load while refusing to provide comparable service to long-term point-
to-point customers. The intent of section 217(k) is to preserve the use
of certain firm transmission rights to the extent required to meet the
service obligations of a class of specified utilities. The statute thus
protects these utilities' continued use of protected firm transmission
rights during periods of constraint or emergency, when service might
not otherwise be available. The transmission provider's use of planning
redispatch (as well as conditional firm service) occurs prior to the
occurrence of such conditions, when the transmission provider decides
to bring a new resource onto its system. It is therefore unduly
discriminatory for the transmission provider to refuse to make planning
redispatch (or conditional firm service) available to similarly
situated customers. Indeed, this furthers the intent of FPA section 217
by facilitating the ability of all long-term users of the transmission
system to meet their service obligations, which the statute defines
broadly to include not only service to end-users, but also to
distribution utilities serving end-users.\213\
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\213\ See EPAct 2005 sec. 1233(a)(3) (to be codified at section
section 217(a)(3) of the FPA, 16 U.S.C. 824q(a)(3)).
---------------------------------------------------------------------------
542. We agree with TAPS that Order No. 890 inadvertently failed to
make modifications to section 32.3 that correspond to the amendments to
19.3 of the pro forma OATT to provide more information for customers
requesting the planning redispatch option. We revise section 32.3 to
make clear that the information required in a system impact study is
nearly identical for network and point-to-point customers. We note that
the amended section 32.3 only requires a transmission provider to
provide an estimate of costs for the network customer to the extent it
has cost data for the relevant network customer's resources.
543. However, we deny TAPS' request to address here the granularity
of system modeling necessary to implement planning redispatch service.
The ATC and planning-related reforms adopted in Order No. 890 will help
address TAPS' granularity issue once these reforms are implemented.
Transmission providers have been directed to address the effect on ATC
of designating and undesignating network resources as part of the
ongoing NERC/NAESB standardization effort.\214\ To the extent TAPS has
concerns regarding the modeling of ATC to respond to requests to
designate network resources, those concerns should be addressed in the
first instance through the NERC/NAESB process. We make no further
changes to the planning and reliability redispatch services in the
existing pro forma OATT as these services are already provided
comparably to network customers.
---------------------------------------------------------------------------
\214\ See Order No. 693 at P 1041.
---------------------------------------------------------------------------
544. We agree with EEI's requested change to provide consistency
between the pro forma OATT and the preamble of Order No. 890. As the
Commission stated repeatedly in Order No. 890, transmission providers
are obligated to provide planning redispatch options only to customers
requesting long-term firm point-to-point service.\215\ We amend section
15.4(b) of the pro forma OATT accordingly. We also revise sections 19.1
and 19.3 of the pro forma OATT to make clear that the planning
redispatch option is available to eligible customers, not just existing
transmission customers, as provided in Order No. 890.
---------------------------------------------------------------------------
\215\ See, e.g., Order No. 890 at P 4, 78, and 911.
---------------------------------------------------------------------------
(2) Conditional Firm
Requests for Rehearing and Clarification
545. Several petitioners object to the Commission's decision to
require transmission providers to offer conditional firm point-to-point
service.\216\ Ameren states that the conditional firm option is not
superior to the options already available to customers under the pro
forma OATT adopted in Order No. 888. Ameren contends that the
conditional firm service options create more discretion and uncertainty
in the processing of service requests, contrary to the Commission's
stated goal of increasing transparency in the provision of transmission
service. Ameren expresses concern that ill-defined conditional firm
service rules could lead to non-compliance and assessment of
significant penalties. Ameren and NorthWestern argue that, at a
minimum, the Commission must provide detailed guidelines and limit the
discretion of transmission providers in studying conditional firm
service options. Ameren states that allowing conditional firm
transmission to be curtailed only during selected events offers less
system reliability. Ameren and NRECA ask the Commission to limit or
remove the obligation to provide conditional firm service because
maintaining the service will degrade reliability as system planners and
operators must account for more and varied uses of the system and
manage increased loadings on the system. If it is not allowed to deny
service for the degradation of reliability that would occur with every
service request involving conditional firm, Ameren asks that the
Commission develop clear reliability guidelines so that transmission
providers can comply without subjecting themselves to claims of
discrimination for denying service.
---------------------------------------------------------------------------
\216\ E.g., Ameren, NRECA, and TDU Systems.
---------------------------------------------------------------------------
546. South Carolina E&G and South Carolina Regulatory Staff contend
that the obligation to offer the conditional firm option contradicts
section 217 of the FPA to the extent it impinges on native load
service. South Carolina E&G states that granting a secondary network
service curtailment priority during conditional curtailment periods
could adversely affect the reliability of native load service in direct
violation of section 217 of the FPA. South Carolina E&G states that
native load customers use secondary network service for redispatch when
the system becomes constrained; therefore, allowing increased use of
this priority non-firm service by conditional firm service customers
will adversely affect native load customers in violation of FPA section
217. South Carolina E&G also argues that FPA section 217(k) precludes
the Commission from finding that the practice of using conditional firm
by transmission providers is unduly discriminatory.
547. MidAmerican requests clarification that transmission providers
are not prohibited from voluntarily offering the conditional firm
option for short-term point-to-point service. MidAmerican also requests
Commission clarification that Order No. 890 did not require
transmission providers to submit revised tariff sheets if the
transmission providers already provide short-term conditional firm
service.
548. Some petitioners ask the Commission to create a conditional
firm network service.\217\ TAPS and NRECA
[[Page 3051]]
contend that limiting the conditional firm option to long-term firm
point-to-point service is inappropriate in light of the Commission's
finding that transmission providers provide themselves conditional firm
network service. TAPS and NRECA argue that the Commission has allowed
continued discrimination as between transmission providers and network
customers. TAPS argues that Order No. 890 enables transmission
providers to continue to designate resources on a conditionally firm
basis, but denies network customers the same right to do so.
---------------------------------------------------------------------------
\217\ E.g., NRECA, TAPS, and TDU Systems.
---------------------------------------------------------------------------
549. NRECA and TDU Systems also contend that conditional firm
network service is required to preserve network customers' ability to
access those resources that they are able to obtain today through
redirect service without being bumped by conditional firm point-to-
point customers. In their view, conditional firm network service would
prevent gaming and hoarding by point-to-point customers through use of
conditional firm service and achieve parity in flexibility through use
of secondary network service. TDU Systems assert that the provision of
conditional firm network service is essential to ensure that network
customers can receive the same priority in maintaining transmission
access rights as those granted to conditional firm point-to-point
customers.
550. NRECA and TDU Systems argue that allowing conditional firm for
the import of designated network resources but not allowing it for in-
control area transactions is irrational, creates perverse operational
incentives and does not make legal sense. By way of example, NRECA
states that a resource could be designated to serve load in a
neighboring control area, but not in the control area in which the
resource is located. NRECA contends that creation of a conditional firm
network service would provide additional support to intermittent
resources that wish to sell their services in the control area in which
these resources are located.
551. Finally, EEI requests clarification of the length of the
service request that would qualify for these options. EEI notes that
sections 15.4(c) of the pro forma OATT does not qualify the provision
of conditional firm service only to long-term firm point-to-point
customers. EEI asks the Commission to amend sections 15.4(c) of the pro
forma OATT to make this section consistent with the statements in Order
No. 890 providing that a transmission provider is obligated to provide
conditional firm service to customers requesting long-term firm point-
to-point service, but not to customers requesting short-term firm
service.
Commission Determination
552. The Commission affirms the decision in Order No. 890 to create
a new conditional firm option in the pro forma OATT for customers
seeking and denied long-term firm point-to-point transmission
service.\218\ We reiterate that, like the planning redispatch option,
transmission providers are not required to provide conditional firm
service if doing so would impair system reliability. Concerns regarding
system reliability have thus already been addressed in the design of
the conditional firm option.
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\218\ As stated above, RTOs and ISOs with real-time energy
markets are not required to offer the conditional firm option. Also,
those transmission providers that do not provide long-term firm
point-to-point service are exempt from providing conditional firm
point-to-point service.
---------------------------------------------------------------------------
553. We disagree with Ameren that the conditional firm option will
create more discretion and uncertainty in processing of service
requests. In Order No. 890, the Commission provided a detailed
description of the characteristics, requirements and implementation of
the new option, developed through multiple industry sessions and with
supplemental comments. Ameren argues that the obligation to offer the
conditional firm option should be eliminated unless the Commission
provides further guidance regarding how to study its availability, yet
Ameren does not identify the particular details that it believes are
missing. Even if there is some initial uncertainty in the processing of
service requests as transmission providers become comfortable with
studying the conditional firm option, it is more than offset by the
reduction in uncertainty faced by eligible customers whose service
requests would otherwise have been rejected for lacking as little as
one hour of firm service during the year.
554. We decline to develop reliability guidelines for the provision
of conditional firm service, as Ameren requests. Each transmission
system will have a different ability to accommodate varying requests
for conditional firm service. As with planning redispatch, any
guidelines we create would necessarily be over or under-inclusive and
either jeopardize the reliability of some transmission providers'
systems or unnecessarily restrict the amount of conditional firm
service that may be offered. Transmission providers may determine the
amount of conditional firm service that they can reliably provide, as
long as they do not reject requests from similarly situated customers.
555. We disagree that requiring transmission providers to offer
conditional firm service violates FPA section 217. As we explain above,
section 217 provides certain protections to a specified class of
utilities using their firm transmission rights, to the extent required
to meet their service obligations. By its very nature, conditional firm
service will be conditional when the transmission provider cannot
accommodate additional firm service in light of other commitments,
including the firm service obligations of LSEs on its system or other
existing customers. Moreover, transmission providers are not required
to offer the service if doing so would impair system reliability. The
restrictions placed on conditional firm service are thus consistent
with, and not in contrary to, the requirements of FPA section 217.
556. We also disagree with South Carolina E&G that conditional firm
service violates FPA section 217 because it will increase the amount
and use of secondary network service, in competition with the use of
secondary network service by native load. Secondary network service,
also called priority non-firm service, is a non-firm transmission
right. Increased use of secondary network service by conditional firm
customers therefore does not disturb the use of firm rights protected
by section 217. Similarly, FPA section 217(k) does not preclude our
finding that failure to offer the conditional firm option is unduly
discriminatory since the conditional nature of the service is not
within the scope of service protected by FPA section 217(b).
557. We clarify in response to MidAmerican that a transmission
provider that provided short-term conditional firm service prior to
issuance of Order No. 890 need not revise the existing tariff
provisions relating to short-term firm service.\219\ A transmission
provider proposing to add short-term conditional firm service to its
OATT must seek approval under FPA section 205. In either case, the
voluntary provision of short-term conditional firm service does not
relieve the transmission provider from the obligation to provide long-
term conditional firm point-to-point service.
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\219\ See Order No. 890 at P 135, n.106.
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558. We affirm the decision in Order No. 890 not to create a
conditional firm network service. Network customers may designate
network resources any time firm transmission is available, and
[[Page 3052]]
the term of the designation can include periods of less than a year.
Network customers can also use secondary network service to access
resources during times when firm service is not available. This
flexibility to use designated network resources and secondary network
service to access undesignated resources already provides a service
that is like conditional firm service that can be used to integrate new
resources, intermittent or otherwise.
559. We agree, however, that transmission providers must study the
use of automatic devices when requested by a network customer in a
system impact study. In Order No. 890, the Commission found that
transmission providers employ automatic devices, such as special
protection schemes, to take resources offline during certain system
conditions. Comparability requires the study of these automatic devices
for network customers seeking to designate network resources. We
disagree with TAPS that comparability further requires the same service
as between network customers and point-to-point customers. In Order No.
890, the Commission reiterated that network service and point-to-point
service were not designed to be identical and, therefore, the rights
and obligations of each type of customer need not be the same.\220\ We
therefore deny rehearing requests to create a network service that is
the same as conditional firm point-to-point service, but revise section
32.3 of the pro forma OATT to require the study of automatic devices at
the request of a network transmission customer.
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\220\ See id. at P 1093.
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560. We acknowledge that conditional firm point-to-point service
may have an impact on a network customer's use of secondary network
service due to increased use of priority non-firm service, but note
that the conditional firm option does not reduce the availability of
secondary network service any more than the use of short-term firm
point-to-point service. Conditional firm point-to-point service could
not possibly disrupt a network customers use of redirect service
because network customers may not redirect their service,\221\ as NRECA
argues, nor does the conditional firm option disrupt the network
customer's use of point-to-point service to secure off-system
resources, since network customers may take conditional firm point-to-
point service if they choose. Finally, NRECA's concerns regarding
potential hoarding are based on a mistaken belief that customers taking
conditional firm service are not charged the long-term transmission
rate. The Commission made clear in Order No. 890 that customers taking
the conditional firm option pay the rate for long-term firm point-to-
point service.\222\
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\221\ See id. at P 1612.
\222\ See id. at P 1047.
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561. We agree with EEI's requested change to provide consistency
between the pro forma OATT and the preamble of Order No. 890. As the
Commission stated repeatedly in Order No. 890, transmission providers
are obligated to provide conditional firm options only to customers
requesting long-term firm point-to-point service.\223\ We amend section
15.4(c) of the pro forma OATT accordingly. We also revise sections 19.1
and 19.3 of the pro forma OATT to make clear that the conditional firm
option is available to eligible customers, not just existing
transmission customers, as provided in Order No. 890.
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\223\ See, e.g., id. at P 4, 78, and 911.
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b. Implementation of Planning Redispatch and Conditional Firm
(1) Characteristics of Service
562. The Commission explained in Order No. 890 that the planning
redispatch and conditional firm options were not services distinct from
point-to-point transmission service, but rather a modification to the
procedures for granting long-term point-to-point service and the
curtailment priorities for that service. The primary purpose of each
option is to address the ``all or nothing'' problem associated with the
current procedures for requesting long-term point-to-point service.
Where a request for long-term point-to-point firm transmission service
is made and cannot be satisfied out of existing capacity, the
transmission provider must, at the request of the customer and in the
system impact study, identify (i) the transmission upgrades necessary
to provide the service and (ii) the options for providing service
during the period prior to completion of those transmission upgrades.
If upgrades cannot be completed prior to expiration of the requested
service term, the transmission provider must, at the request of the
customer and in the system impact study, identify options for providing
the service during the requested term. The options studied by the
transmission provider must include both planning redispatch and
conditional firm options. The transmission provider, at its discretion,
may study and offer a mix of planning redispatch and conditional firm
options for a single service request.
563. If the transmission provider determines that planning
redispatch or conditional firm options are available, the system impact
study must identify the following: (i) The system constraints,
identified by transmission facility or flowgate, causing the need for
the system impact study; (ii) additional direct assignment facilities
or network upgrades required to provide the requested service; (iii)
redispatch options, including the relevant congested transmission
facilities for which redispatch will be provided, the generation
resources that can relieve those congested facilities, the impact of
each identified resource on the congested facilities, and an estimate
of the incremental costs of redispatch; and (iv) conditional firm
options, including the annual number of conditional curtailment hours
and the specific system conditions during which conditional curtailment
may occur.\224\ Transmission providers may recover the costs of
studying these options through the system impact study agreement.
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\224\ The Commission did not require a standardized method of
modeling the hours in which conditional firm point-to-point service
would be conditional, although it did state addition of a risk
factor to their calculation of annual curtailment hours would be
appropriate to account for forecasting risks.
---------------------------------------------------------------------------
564. If the customer agrees to take service, the service agreement
must specify the relevant congested transmission facilities and whether
the transmission provider will provide planning redispatch, a mix of
planning redispatch and conditional firm, or conditional firm in order
to provide the point-to-point transmission service. For the conditional
firm option, customers must choose among, and the service agreement
must specify, either (i) specific system condition(s) during which
conditional curtailment may occur \225\ or (ii) annual number of
conditional curtailment hours during which conditional curtailment may
occur.\226\ In situations in which the customer commits to paying the
costs
[[Page 3053]]
associated with upgrades necessary to provide the service on a fully
firm basis, the conditions or hours identified by the transmission
provider must remain in effect until such time as the upgrades have
been completed. For such customers, the service agreement must specify
the upgrade costs as determined through the facilities study.
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\225\ Acceptable system conditions could include designation of
limiting transmission elements, such as a transmission line,
substation or flowgate. The Commission stated its belief that
designation of system load levels, standing alone, would not qualify
as an acceptable system condition. Load levels would have to be
linked to a specific constraint or transmission element that is
associated with the request for service, e.g., load levels in a
constrained load pocket.
\226\ Although the Commission did not require use of monthly or
seasonal caps, it encouraged transmission providers to offer them if
they can overcome modeling barriers, since monthly or seasonal caps
would give more certainty to customers regarding the particular
aspects of their service.
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565. Any service agreement that incorporates planning redispatch or
conditional firm options will be considered a non-conforming agreement
and must be filed by the transmission provider pursuant to FPA section
205. Transmission providers therefore must also file with the
Commission any amendments to these service agreements that result from
reassessments. If a transmission provider proposes to change the
redispatch or conditional curtailment conditions due to a reassessment,
the Commission obligated transmission providers to provide the
reassessment study to the customer along with a narrative statement
describing the study and reasons for changes to the curtailment
conditions or redispatch requirements no later than 90 days prior to
the date for imposition of these new conditions or requirements.
566. During non-conditional periods, conditional firm service is
subject to pro rata curtailment consistent with curtailment of any
other long-term firm service. During the hours or specific system
conditions when conditional firm service is conditional, conditional
firm service share the same curtailment priority as secondary network
service. In such circumstances, transmission providers will be allowed
to curtail only for reliability reasons and conditional firm customers
during conditional curtailment hours will be curtailed only after all
point-to-point non-firm customers have been curtailed. If the customer
selects the annual hourly cap option, the transmission provider will
have the flexibility to conditionally curtail the customer for any
reliability reason during those hours, including but not limited to,
the system condition(s) identified in the system impact study.
567. The Commission provided that short-term firm service reserved
prior to the reservation of conditional firm service will maintain
priority over conditional firm service in the periods when conditional
firm service is conditional, i.e., when specified system conditions
exist or conditional curtailment hours apply. Transmission providers
were directed to work with NAESB to develop the appropriate
communications protocol to allow for automatic assignment of short-term
firm point-to-point service to conditional firm customers to the extent
short-term service becomes available. Transmission providers need not
implement this requirement until NAESB develops appropriate
communications protocols.
568. Transmission providers also were directed to work with
customers to facilitate the use of third party generation, where
available, in provision of planning redispatch. To facilitate provision
of redispatch service by third parties, the Commission further directed
transmission providers, working through NAESB, to modify their OASIS
sites and develop any necessary business practices to allow for posting
of third party offers to provide planning redispatch. Again,
transmission providers were not required to implement the new OASIS
functionality and any related business practices until NAESB develops
appropriate standards.
569. Finally, the Commission recognized that there may be some
regional variation in the way transmission providers approach the
provision of conditional firm service beyond the minimum attributes
that established in Order No. 890. The Commission directed transmission
providers located in the same region to coordinate among themselves to
develop business practices for implementation of the conditional firm
service.\227\ In order to allow time for this regional coordination,
the Commission directed transmission providers to implement these
mechanisms and business practices within 180 days after the publication
of this Final Rule in the Federal Register, or October 11, 2007.
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\227\ The Commission encouraged participation of non-public
utility transmission providers in the region and interested
transmission customers in the development of these business
practices, and directed public utility transmission providers to
make efforts to include these interested parties in their regional
coordination efforts.
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Requests for Rehearing and Clarification
570. AWEA argues that the Commission erred in limiting the term of
planning redispatch and conditional firm services. AWEA contends that
longer-term planning redispatch and conditional firm services would
better meet the needs of customers seeking long-term service that are
unable to secure transmission upgrades because they are uneconomic. If
the Commission declines to eliminate temporal limitations on the
transmission provider's obligation to offer these services, AWEA asks
the Commission to extend the reassessment period from two years to five
years. AWEA argues that a five year reassessment period may allow
customers to secure financing and would be reflective of a more typical
planning horizon.
571. In contrast, NRECA asks that the Commission not allow planning
redispatch or conditional firm point-to-point service unless customers
agree to pay for transmission upgrades. NRECA argues doing so will
eliminate the transmission customer's incentive to free-ride on
transmission capacity built and paid for by others. Southern requests
clarification that transmission customers committing to transmission
construction have a higher priority for the incremental transmission
capacity created by their upgrades than planning redispatch or
conditional firm customers. If this priority is not granted, Southern
maintains that planning redispatch and conditional customers not
willing to commit to such construction could firm up their product by
waiting for later-queued customers to pay for and construct the
upgrades.
572. EEI and Southern argue that bridge customers should also be
subject to the biennial reassessment when the period for completing
upgrades exceeds two years. EEI contends that, unlike reassessment
customers, bridge customers receive a lower quality of service compared
to non-bridge customers because the transmission provider makes their
determinations using the lowest ATC conditions that occur during the
entire term of the bridge service agreement. EEI argues that the
transmission provider therefore incorporates a larger margin of risk
into its initial offer of service to the bridge customer than would be
necessary if it were able to reassess the service biennially.
573. Constellation and EPSA request clarification that the biennial
reassessment is not a de novo review of whether or not to provide
conditional firm service and, instead, is limited to evaluation of the
triggering conditions that were identified in the initial analysis.
EPSA argues that if the transmission provider's studies show that only
one of 10 key facilities raises reliability concerns that warrant an
offer of conditional firm service, the transmission provider must be
required to plan for and maintain all facilities other than the one
identified limiting element on an ongoing basis. Otherwise, EPSA
contends, conditional firm service denigrates into a two year service
obligation. MidAmerican asks the Commission to confirm that
transmission providers can waive their rights to reassess planning
redispatch and conditional firm service for all similarly situated
customers. MidAmerican suggests that transmission
[[Page 3054]]
providers be able to waive reassessment rights for customers in areas
experiencing infrequent changes, but maintain their reassessment rights
for other customers in areas that experience frequent changes.
MidAmerican contends that a transmission provider's act of waiving the
reassessment should not be considered an act of discretion that
requires an OASIS posting. MidAmerican also requests clarification that
waiver of one reassessment period does not constitute an infinite
waiver of reassessment rights. EEI asks the Commission to confirm that
the transmission customer bears responsibility for the costs of the
biennial reassessments since they are performed in response to its
service request.
574. E.ON U.S. expresses concern that, if transmission providers
are completely divorced from the third-party provided planning
redispatch, there may be a negative impact on system reliability and
ATC. E.ON U.S. requests clarification that the reliability coordinator
for the transmission system must oversee third-party provision of
planning redispatch to avoid interference with reliability redispatch.
575. MidAmerican seeks rehearing of the Commission's decision to
expand the scope of the conditional firm option beyond the original
NOPR proposal to include curtailment based on system conditions.
MidAmerican asserts that this expansion assumes that the system has a
built-in ability to absorb scheduled flow of energy from full
utilization of firm or network service plus flows from contingent firm
service upon an instantaneous system contingency until an operator can
curtail conditional firm service. MidAmerican argues that contingencies
on certain systems, such as systems susceptible to rapid voltage
collapse and cascading outages, can occur before the operator can
respond by curtailing.
576. Some petitioners argue that the transmission provider, not the
transmission customer, should choose whether conditional firm
curtailment will be based on an identified system condition or number
of annual hours.\228\ Ameren asserts that a system contingency event is
not interchangeable with a number of hours limitation because they
produce vastly different impacts on the system. Ameren and E.ON U.S.
contend that modeling processes and changes in system conditions
provide uncertainty and will hinder the transmission provider from
specifying accurate curtailable hours. NRECA suggests that the decision
of which approach to use should be driven by the results of the
transmission provider's studies, local system conditions governing the
availability of transmission, and a concern for preserving the
reliability and value of existing firm service. E.ON U.S. asks the
Commission to acknowledge that the risk factor associated with the
number of hours that a customer can be curtailed for conditional firm
service may be substantial to reflect the possibility of unexpected
events such as a car accident, hurricane, or ice storm that require
curtailment of transmission over a certain path.
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\228\ E.g., Ameren, NRECA, and Southern.
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577. EEI argues that the Commission should grant rehearing
regarding the curtailment priority of conditional firm service during
conditional periods. To allow the same curtailment priority as
secondary network service, EEI asserts, would adversely impact reliable
service to network and native load customers because these customers
use ``secondary network service in order to serve network loads
reliably.'' \229\ Additionally, EEI argues that providing a curtailment
priority that is below that of secondary network service instead of
equal to it does not violate the prohibition against undue
discrimination or impact comparability.
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\229\ Citing Order No. 890 at P 1601.
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578. Southern, EEI and Transerv state that there is no automated
process in NERC's Interchange Distribution Calculator (IDC) to convert
a tag from firm priority to non-firm priority in order to accommodate
conditional firm service. EEI states that currently the only way to
modify the curtailment priority reflected on a tag is to cancel the
existing tag and issue a new one. According to EEI, this affects the
quality of service and ultimately causes the customer to incur
imbalance charges. Southern, EEI and Transerv encourage implementation
of uniform tagging business practices developed by NAESB to bring
greater uniformity to markets. Transerv and EEI also request that the
implementation deadline be extended to allow time for these
modifications.
579. Southern also argues that the conditional firm service
requirements may conflict with NERC reliability standards which require
the transmission provider to demonstrate that its transmission system
is planned such that it can be operated to supply projected demands and
firm transmission services. Southern contends that if conditional firm
service is modeled in the base case, it will cause overloads under N-1
contingencies resulting in the curtailment of firm transactions in
contravention of NERC planning criteria. Southern asks the Commission
to clarify that a transmission provider will not be in violation of
NERC reliability standards by providing conditional firm service or if
so that civil penalties will not be imposed for such violations.
580. TDU Systems ask the Commission to require transmission
providers to update their rates to reflect the new conditional firm
service revenues and to report to the Commission annually any revenues
from this service.
Commission Determination
581. The Commission affirms the decision in Order No. 890 to
require transmission providers to provide planning redispatch and
conditional firm service subject to a biennial reassessment when
transmission customers are unwilling to pay for transmission upgrades.
We decline to adopt a longer reassessment period or altogether
eliminate the reassessment feature of these services. There are
legitimate circumstances under which a customer may choose not to
support system upgrades, including high construction costs or a short
term of service that does not merit construction. Balanced against
these customers' needs are the needs of transmission providers to
reliably provide service and of other customers to continue using their
own firm transmission rights. Adopting a two year reassessment period
appropriately balances these various interests.
582. The Commission did not, as AWEA suggests, limit the term of
the reassessment service. A customer taking planning redispatch or
conditional firm service subject to reassessment could receive an
unlimited term of service, with the transmission provider reassessing
every two years the redispatch required to keep the service firm or the
conditions or hours under which the transmission provider may
conditionally curtail the service.\230\
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\230\ We clarify in response to EEI that conditional firm and
planning redispatch customers should pay for the costs of conducting
their individual biennial reassessments.
---------------------------------------------------------------------------
583. We disagree with EEI and Southern that customers supporting
transmission upgrades should be subject to the biennial reassessment.
In Order No. 890, the Commission required the specification of
unchanging conditions in a transmission service agreement for a
customer willing to pay for upgrades.\231\ Customers agreeing to take
service under this bridge product require certainty because they
typically are financing and constructing new resources. While we
recognize that a
[[Page 3055]]
transmission provider may need to incorporate a larger margin of risk
into the analysis of conditions when a customer has agreed to pay for
upgrades that will not be brought online for several years, we do not
believe that this will most often be the case. We require transmission
providers to study the conditions for bridge service as they would
their own use of a similar service used prior to the completion of
transmission upgrades. Only those transmission providers using large
margins of risk in evaluating the acquisition or construction of their
own new resources with long transmission construction lead times should
apply large margins of risk to the study of the conditional firm
service for a customer that agrees to pay for upgrades.
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\231\ See id. at P 980.
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584. We agree with Southern that customers paying for upgrades have
priority access to the capability created by those upgrades, up to the
point of the amount of transmission service requested. To do otherwise
would create disincentives for transmission customers later in the
queue to pay for upgrades because upgrades must necessarily be sized to
accommodate all earlier-queued customers. We note, however, that any
capacity created in excess of the service request should be allocated
to those planning redispatch and conditional firm customers earlier in
the queue, based on their order in the queue.
585. We also agree with MidAmerican that a transmission provider's
waiver of a reassessment for conditional firm or planning redispatch
service does not constitute a waiver of all reassessments for the
duration of the service, unless explicitly agreed to by the
transmission provider. We reiterate, however, that only one
reassessment may be performed in each two-year period of service. We
also affirm that any waiver must be granted for similarly situated
service, which would include conditional firm or planning redispatch
service that is limited because of the same constraints or general
system limitations. Such a waiver would be an act of discretion that
must be posted on OASIS. Waiver of the reassessment presents an
opportunity for discrimination among classes of customers on the part
of the transmission provider and posting will provide eligible
customers with an indicator of how often conditions or redispatch
requirements have been reassessed. Transmission providers are directed
to develop uniform OASIS posting standards, in coordination with NAESB,
for transmission providers to post information regarding waivers of the
biennial reassessment for planning redispatch and conditional firm
service.
586. We reiterate in response to E.ON U.S. that both the
transmission provider and reliability coordinator play a role in
ensuring that reliability is maintained when a customer uses third-
party provided planning redispatch.\232\ Customers are allowed to use
their own or third-party resources to secure planning redispatch
services in lieu of or in addition to service from the transmission
provider, provided that the arrangements are sufficiently detailed and
coordinated with the transmission provider to ensure that reliability
is maintained. This would entail review of redispatch plans submitted
by customers, coordination between the transmission provider and
reliability coordinator, and signaling third party generators when the
redispatch is needed. The Commission made clear in Order No. 890 that
it would be the customers' ultimate responsibility to ensure that any
technical arrangements required by the reliability coordinator are in
place in order to maintain reliability.
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\232\ See id. at P 1004-07.
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587. With regard to the conditional firm option, we continue to
require that transmission providers study and offer service based on
both system conditions and annual curtailment hours. The Commission
introduced the concept of conditional curtailment based on system
conditions in its request for supplemental comments issued on November
15, 2006. MidAmerican and other industry participants were therefore
provided adequate notice and opportunity to comment on the potential
for the Commission to expand the scope of the required offerings for
conditional firm service. Upon review of these comments, the Commission
allowed transmission providers to determine system conditions and
conditional curtailment hours through different means, implicitly
recognizing that system conditions are not exactly interchangeable with
conditional curtailment hours.\233\ Modeling of conditional curtailment
hours entails difficulties beyond those encountered in modeling ATC.
Transmission providers have therefore been granted flexibility in
making these determinations and are allowed to use an additional risk
factor in calculating conditional hours.\234\ In light of the
flexibility provided to transmission providers, we reject as
unsupported petitioners' requests to eliminate or limit the requirement
to offer conditional firm service based on the number of hours in which
service may be conditional.\235\
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\233\ See id. at P 1065-67.
\234\ See id. at P 1067.
\235\ We decline requests to extend the date for implementing
conditional firm service, which has already passed.
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588. In Order No. 890, the Commission allowed transmission
providers to add a risk factor to their calculation of annual
curtailment hours to account for forecasting risks. We decline to
clarify the level of this risk factor as E.ON U.S. requests.
Transmission providers need flexibility in modeling these conditions
and we will not specify a level of appropriate risk factor to apply. We
note however that E.ON U.S. lists events that should not be evaluated
in such analysis. Car accidents, hurricanes, ice storms or other
unexpected events that require curtailment of firm transmission
customers taking service over a certain path should not impact the
number of non-firm curtailments of conditional firm service.
589. We disagree with MidAmerican's characterization of curtailment
based on system conditions as requiring automatic or immediate operator
response. Transmission providers, especially those with systems
susceptible to rapid voltage collapse and cascading outages, should
manage these situations as they would manage any other emergency. The
ability to conditionally curtail conditional firm service is not meant
to address system emergencies, but rather address system conditions
such as congestion on a line or flowgate, system load levels or the
outage of a specific line or generator. We affirm the decision in Order
No. 890 to require transmission providers to offer eligible customers
seeking conditional firm service a choice between conditional
curtailment based on specified system conditions or annual hours.
590. We clarify in response to Constellation and EPSA that, when a
transmission provider is evaluating its continued ability to provide
conditional firm service during a biennial reassessment, the
transmission provider is not limited to the specific conditions
previously agreed to by the transmission customer in the initial
service agreement or a prior reassessment. The purpose of the biennial
reassessment is to allow the transmission provider to adjust the
conditions or number of hours during which conditional firm service
will be conditional in order to ensure that continued provision of the
service does not impair reliability. Thus, the Commission does not
impose upon the transmission provider the obligation to plan its system
to keep firm the part
[[Page 3056]]
of the conditional firm service that is firm when service was
initiated. Although this may increase (or decrease) the number of hours
in which service is conditional, the transmission provider may not
entirely terminate service to the conditional firm customer.
591. We affirm our decision to assign conditional firm service the
same curtailment priority as secondary network service for periods when
the service is conditional. EEI's argument that customers use secondary
network service to meet the reliability needs of their loads is
inapposite. Secondary network service is a non-firm service for which
requests are made in the same timeframe as other non-firm service.\236\
While the Commission recognized that network customers may use
secondary network service on an ``as available'' basis to meet peak
native load, and in this way meet the reliability needs of loads, this
is not the purpose of secondary network service. Network customers that
rely upon secondary network service to meet their peak native load are
already lessening the reliability of their service by taking non-firm
service. The fact that conditional firm service will compete with
secondary network service when curtailments are ordered is irrelevant.
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\236\ See id. at P 1606.
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592. We agree with petitioners that the NAESB rules regarding
tagging do not allow a transmission provider to change the tag of a
transmission customer. That is why, in Order No. 890, the Commission
directed transmission providers to coordinate with other transmission
providers in their regions to develop their own business practices to
implement the tagging and tracking of conditional firm service.\237\
Upon consideration of petitioners' concerns, we grant rehearing to
require transmission providers, in coordination with NERC and NAESB, to
develop within 180 days of publication of this order in the Federal
Register a consistent set of tracking capabilities and business
practices for tagging for implementation of conditional firm service.
We agree with petitioners that a consistent set of practices followed
by the industry will reduce transmission provider discretion and bring
uniformity in implementing conditional firm service. In the interim,
the existing business practices of each transmission provider for
tracking and tagging conditional firm service shall remain in effect.
---------------------------------------------------------------------------
\237\ See id. at P 1077. We clarify that transmission providers
may determine the season, month and hour for changing the priority
of tags for customers taking the annual hourly conditional firm
option.
---------------------------------------------------------------------------
593. We decline to generically waive potential penalties for
violations of NERC reliability standards due to implementation of
conditional firm service, as Southern suggests. Southern has not
provided enough information to allow us to determine whether its
implementation of conditional firm service will actually cause
violations of NERC planning criteria. Transmission providers are able
to incorporate the specifics of a conditional firm service agreement in
their base models to differing degrees, depending on the flexibility of
different models and the assumptions used in modeling the service.
Therefore, incorporation of conditional firm service into the base case
of models need not cause overloads under N-1 conditions. Under the
Commission's regulations, if Southern believes a conflict exists
between its implementation of the conditional firm option and any of
NERC's reliability standards, it must bring that conflict to the
attention of the Commission, the Electric Reliability Organization and
the relevant Regional Entity for resolution. Pending resolution of the
matter, a transmission provider must continue to comply with Order No.
890 and provide conditional firm service.
594. Finally, we reject as unnecessary TDU Systems' request to
require separate annual reporting of conditional firm service revenues.
We also decline to generically require all transmission providers to
address potential updates to transmission rates as a result of
providing conditional firm service. TDU Systems has not justified
treating these revenues differently than other long-term firm point-to-
point revenues.
(2) Pricing of Planning Redispatch
595. The Commission determined that customers taking long-term
point-to-point service with planning redispatch will have the option of
paying either (i) the higher of (a) actual incremental costs of
redispatch or (b) the applicable embedded cost transmission rate on
file with the Commission or (ii) a fixed rate for redispatch to be
negotiated by the transmission provider and customer and subject to a
cap representing the total fixed and variable costs of the resources
expected to provide the service. If the customer selects the higher of
incremental cost or the embedded-cost rate, the transmission provider
must calculate the incremental costs of redispatch monthly and charge
the higher of redispatch or the embedded cost rate each month.
596. For purposes of calculating planning redispatch charges,
incremental costs must include fuel or purchase power costs caused by
ramping up generator(s) at the point of delivery and ramping down
generator(s) at the point of receipt. Where applicable, transmission
providers also may specify other incremental costs for inclusion in the
monthly actual incremental costs, including opportunity costs and
purchased power costs, provided that identification and derivation of
these costs is included in the service agreement. All information
necessary to calculate and verify opportunity costs must be made
available at the request of the transmission customer.\238\
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\238\ Although a transmission provider is not required to
contract with a third party to provide planning redispatch, if it
does so then the customer would be obligated to pay the purchase
power costs, including any reservation charge for the power. Any
flow-through of purchase power costs must be negotiated between
customers and transmission providers in a stand-alone agreement if
the transmission provider agrees to make purchases on the customer's
behalf.
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Requests for Rehearing and Clarification
597. Several petitioners argue that customers choosing planning
redispatch should pay the cost of transmission service and the cost of
redispatching generation.\239\ These petitioners generally maintain
that the redispatch of generators merely reallocates use of existing
transmission capability without creating any new thermal transmission
capacity. EEI and Progress contend that planning redispatch takes away
firm transmission capacity from network customers and the transmission
provider's native load and gives that capacity to a new point-to-point
customer, without any corresponding increase in TTC. Southern notes
that customers agreeing to third-party provided planning redispatch
will pay both the embedded transmission rate to the transmission
provider and the redispatch rate charged by the third-party generator.
EEI and Southern contend that the pricing of planning redispatch should
be aligned with the price of reliability redispatch and the pricing for
third-party provided redispatch, arguing that different cost recovery
for similarly situated generators is unduly preferential.
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\239\ E.g., Ameren, EEI, Progress, Southern, Washington IOUs,
and Xcel.
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598. EEI also argues that the Commission's prohibition against
recovery of both the incremental cost of transmission upgrades and the
embedded cost of transmission service from the same customer has a
different impact on the transmission provider's ability to recover its
cost of service than does the prohibition against the recovery of the
costs of planning redispatch and the costs of the
[[Page 3057]]
transmission system. When a transmission provider constructs additional
transmission capacity to serve a new customer, EEI states that the
transmission provider recovers the entire cost of its transmission
system and its new facilities and that the only question is how those
costs should be allocated between new and existing customers. EEI
contends that the pricing for planning redispatch leaves the
transmission provider unable to recover additional costs associated
with the service.
599. Southern argues that customers will receive two distinct
services and should be charged for both according to cost causation
principles. Southern asserts that the Commission's pricing policy for
planning redispatch service results in an uncompensated taking of the
utility's property by providing no compensation for either the
transmission or the generator-supplied redispatch service. Southern
concludes that the rate for planning redispatch cannot be just and
reasonable because the transmission provider will provide part of the
service for free. E.ON. U.S. similarly argues that LSEs should have the
opportunity to recover actual fuel costs since those costs are directly
attributable to the service provided to the redispatch customer. Ameren
asks the Commission to clarify that all costs, including lost
opportunity costs will be recovered in order to avoid penalizing the
generator and harming native load customers.
600. EEI argues that the Commission's rationale for prohibiting the
recovery of both lost opportunity costs and the cost of transmission
service in a pre-open access environment is inapplicable to the
situation that transmission providers face when they must redispatch
generating resources to create transmission capacity that would
otherwise be unavailable.\240\ According to EEI, the situation in
Penelec, in which the utility was seeking compensation for the
potential loss of future imports of non-firm energy, is inapposite to
the planning redispatch requirement, in which the customer's request
for firm service has priority over the transmission provider's non-firm
use of the system.
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\240\ Citing Pennsylvania Electric Company, 58 FERC ] 61,278 at
62,873, reh'g denied, 60 FERC ] 61,034 (1992), aff'd sub nom.
Pennsylvania Electric Co. v. FERC, 11 F.3d 207 (D.C. Cir. 1993)
(Penelec).
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601. If the Commission does not allow recovery of the costs of both
transmission service and the cost of redispatching generation, EEI and
Southern ask the Commission to clarify rate treatment for the planning
redispatch service. They argue that the long-term point-to-point
reservation that employs planning redispatch should not be included in
the divisor of a transmission provider's rate calculation. Instead,
Southern argues that generation-related payments associated with the
redispatch should be treated as a revenue credit to off-set native load
customers' fuel adjustment clause and transmission revenues from the
planning redispatch service should be included in the numerator as a
revenue credit. EEI contends that transmission providers should be
permitted to make a rate design change through amendments to their
formula rates or in a general or single rate case filing.
Commission Determination
602. The Commission affirms the decision in Order No. 890 not to
adopt ``and'' pricing for planning redispatch service. In Order No.
890, the Commission explained that planning redispatch differs from
reliability redispatch in that planning redispatch service creates
additional transmission capacity \241\ and reliability redispatch
allows customers to avoid real-time curtailments.\242\ It is
appropriate for customers to pay the embedded cost of transmission and
the cost of third-party redispatch because third parties cannot recover
transmission revenues for the additional transmission capability
created by their redispatch. Thus, different cost recovery for third
party, network and transmission provider resources providing redispatch
is not unduly preferential.
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\241\ See Order No. 890 at P 1029 (citing Order No. 888-A at
30,267). In Order No. 888-A, the Commission began its discussion of
the redispatch obligation and redispatch pricing by explaining that
``the obligation to create additional transmission capacity to
accommodate a request for firm transmission service should properly
lie with the transmission provider, not a network customer.'' See
Order No. 888-A at 30,267. Because a network customer cannot add new
transmission upgrades on its own to the transmission provider's
system, the Commission was necessarily referring in this statement
to the planning redispatch obligation.
\242\ See Order No. 890 at P 1028.
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603. While we agree that planning redispatch does not create new
thermal capacity equivalent to grid expansion, we disagree with EEI and
Southern that planning redispatch does not create additional
transmission capability and associated revenues for the transmission
provider. When a transmission provider plans to redispatch its
generation resources in order to provide previously unavailable firm
point-to-point service, it does not and should not take firm service
away from network and native load customers. The transmission provider
continues to provide firm service to network and native load customers
and receives its revenue requirement to serve those customers. The
transmission provider also adds another long-term firm point-to-point
service agreement and receives its embedded cost transmission rate for
that service, which it would not have received but for providing the
planned redispatch of its resources.
604. The pricing of planning redispatch service does not violate
cost causation principles or amount to an uncompensated taking from
utilities. Transmission providers will receive on a monthly basis the
higher of the cost of redispatching their generators or the revenues
for transmission service that they would not have received but for the
redispatch. Transmission providers do not provide the redispatch of
their generation for free, as Southern contends, nor do they lose the
opportunity to recover actual fuel costs, as E.ON U.S. suggests. If the
monthly embedded-cost transmission rate is lower than the monthly costs
of redispatching resources, including actual fuel costs, the higher
monthly redispatch costs may be recovered.
605. We will not allow ``and'' pricing of planning redispatch
service, which would result in overcompensation of transmission
providers and violate the Commission's long-standing opportunity costs
pricing policy announced in Penelec. In Order No. 888, the Commission
affirmed the rationale in Penelec for allowing utilities to charge
opportunity costs in an open access environment.\243\ In Order No. 888-
A, the Commission specifically concluded that opportunity cost pricing
is appropriate for costs that arise from a transmission provider having
to reduce its off-system sales to avoid a transmission constraint and
reiterated that off-system sales can only be made pursuant to the
point-to-point provisions of the pro forma OATT.\244\ The Commission
also affirmed that ``and'' pricing is not appropriate for planning
redispatch service.\245\ EEI's assertion that Penelec is not applicable
in a post-open access world is a collateral attack on Order Nos. 888
and 888-A.
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\243\ See Order No. 888 at 31,739.
\244\ See Order No. 888-A at 30,265, n.261.
\245\ Id.
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606. Order No. 888 provided that revenues from direct assignment of
redispatch costs must be credited to the costs of fuel and purchased
power expense included in the transmission provider's wholesale fuel
adjustment
[[Page 3058]]
clause.\246\ We therefore clarify that, in months in which generation-
related payments are collected for planning redispatch, these payments
should be treated as a revenue credit to off-set native load customers'
fuel adjustment clause. In months in which the embedded cost rate of
transmission is collected for planning redispatch, these revenues
should be included in the numerator of the rate calculation as a
revenue credit. For most planning redispatch service, we believe that
there will likely be at least one month a year when the actual
incremental cost of redispatch is higher than the embedded cost rate.
For this reason we believe it is appropriate for transmission providers
to treat transmission revenues from planning redispatch service
consistent with the rate treatment for revenues from short-term
transmission reservations. To the extent necessary, a transmission
provider may propose in an FPA section 205 filing any rate design
change that may be necessary through an amendment to its formula rate
or in a general or single rate case filing.
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\246\ See Order No. 888 at 31,740.
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(3) Rollover Rights
607. The Commission found in Order No. 890 that rollover rights are
appropriate for point-to-point service that is provided using planning
redispatch or conditional firm options and that would otherwise be
eligible for rollover rights. The transmission provider, however, will
continue to have a right to review the conditions or redispatch
requirements every two years.
608. The Commission determined that a conditional firm customer
opting to roll over will retain a priority claim to the portion of its
service that is firm. The Commission qualified this statement by
providing an example: if a five-year conditional firm service initially
has a 100-hour annual cap on curtailments, but the cap is later
reassessed at 150 hours, the rollover right would continue to give the
customer first call on all but the 150 hours as against all other
subsequent requests for firm service.
Requests for Rehearing and Clarification
609. TDU Systems and Ameren argue that the Commission erred in
allowing rollover rights for conditional firm service that is subject
to biennial reassessment. TDU Systems and Ameren argue that allowing
rollover for this service is inconsistent with other requirements of
Order No. 890 that limit conditional firm service to the shorter term
service if customers do not agree to pay for upgrades. TDU Systems
contend that allowing rollover rights for customers taking conditional
firm service creates a continued opportunity for transmission customers
to free ride on transmission capacity built and paid for by others.
Ameren maintains allowing rollover rights for conditional firm
agreements will increase uncertainty in modeling and will decrease the
incentive to upgrade the transmission system.
Commission Determination
610. The Commission affirms the decision in Order No. 890 to
provide rollover rights to conditional firm point-to-point service that
otherwise qualifies for rollover rights. We disagree that granting
rollover rights to conditional firm customers is inconsistent with
statements in Order No. 890 that customers not willing to pay for
upgrades should have their service limited. Customers taking
conditional firm service subject to reassessment take the risk that the
firmness of their service will deteriorate with every biennial
reassessment. These customers are not free riding on the transmission
grid, but rather are taking less than firm service and making a
contribution to the embedded costs of the grid by paying the long-term
firm transmission rate. Allowing rollover will not increase uncertainty
in modeling the service, as Ameren contends, because transmission
providers will still be able to perform biennial reassessments every
two years for those conditional firm customers not willing to pay for
upgrades.
611. We also disagree that granting rollover rights to conditional
firm customers decreases incentives to expand the grid. Even without
rollover rights, conditional firm customers wishing to continue their
service could simply submit additional requests for service, in
response to which the transmission provider would identify the limiting
conditions for continued service. Granting rollover rights to longer-
term conditional firm customers allows these customers to keep their
place in line ahead of others seeking conditional firm service in
recognition of the longer-term commitment they made to the transmission
provider. Ameren's concern, then, is with the underlying requirement to
offer conditional firm service, which we affirm above.
(4) Use of the Conditional Firm Option in Designating Network Resources
612. In Order No. 890, the Commission concluded that conditional
firm point-to-point service is sufficiently firm to support the
designation of network resources imported from other control areas. The
Commission concluded that the conditional firm option only affects the
transmission of the resource to the network, not the interruptibility
of the generating resource itself, and the transmission may not be
interrupted for reasons other than reliability.
Requests for Rehearing and Clarification
613. Several petitioners object to allowing conditional firm
service to be used to support an off-system designated network
resource.\247\ EEI and Progress argue that allowing designation of such
resources would adversely impact system reliability. EEI asserts that
some customers may take conditional firm service that is curtailable in
all summer months, not just 10 to 20 hours a year. EEI contends that
conditional firm service presents the possibility that the supply of
energy from a generator may be interrupted for a substantial period of
time, well in excess of the time for an interruption due to a forced
outage or maintenance outage. EEI asserts that this less reliable
service to serve load will not only impact the conditional firm
customer's supply of energy, but could affect other network customers
and native load customers.
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\247\ E.g., Duke, EEI, Progress, and TDU Systems.
---------------------------------------------------------------------------
614. Duke requests clarification that off-system conditional firm-
supported resources may qualify as designated network resources only if
the network customer clearly specifies in its Network Integration
Transmission Service Agreement specific backup arrangements, such as
adequate reserves. Duke also asks the Commission to clarify that a
transmission provider need not undertake provider-of-last-resort
obligations to any network customer that elects to designate a network
resource supported by conditional firm service.
615. PJM asks the Commission to clarify that Order No. 890 does not
require it to accept conditional firm service as sufficient to qualify
external generating resources as capacity resources for purposes of
PJM's Reliability Pricing Model (RPM). In order to qualify as a
capacity resource, PJM asserts that an external unit must have a firm
path to load that is available year-round, particularly during high-
level periods when adjacent control areas both are experiencing system
stresses.
[[Page 3059]]
Commission Determination
616. The Commission affirms the decision in Order No. 890 to allow
the designation of off-system resources supported by conditional firm
point-to-point service.\248\ It is appropriate to allow conditional
firm service to support the designation of network resources because
the conditional firm option only affects the transmission of the
resource to the network, not the interruptibility of the generating
resource itself. Conditional firm service satisfies the requirement
that the delivery of the resource to the network to be non-
interruptible because conditional firm transmission service is
curtailable only for specific reliability reasons, not for economic
reasons.
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\248\ See Order No. 890 at P 1091.
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617. We acknowledge that conditional firm service may have
conditions that apply for most of the peak periods of a month or
season. This does not mean that such service will necessarily impact
the reliability of the transmission provider's system. The Commission
declines Duke's request to require a network customer with a designated
off-system resource supported by conditional firm service to obtain
reserves or backup resources to cover the periods when the resource
supported with conditional firm point-to-point transmission service
might not be delivered. It is not the responsibility of the
transmission provider to ensure that the network customer has
sufficient resources to meet its load.
618. Whether or not off-system resources supported by conditional
firm service may serve as a capacity resource under PJM's RPM is
governed by the relevant RPM rules adopted by PJM, which were not
addressed in Order No. 890.
c. Proposals for Transparent Redispatch
619. In Order No. 890, the Commission rejected requests to expand
the transmission provider's real-time redispatch obligations to
incorporate third-party bids for redispatch or otherwise require
reliability redispatch to be offered to point-to-point customers. The
Commission concluded that the provision of reliability redispatch only
to network customers did not constitute undue discrimination because,
unlike point-to-point customers, network customers are required to make
their generation resources available to the transmission provider to
provide reliability redispatch to maintain the reliability of both
native load and network service. The Commission also determined that
mandatory inclusion of third party offers to redispatch is not
necessary to remedy undue discrimination because, unlike the
transmission provider, third party generators are under no obligation
to make their resources available to provide redispatch.
620. The Commission did, however, require that transmission
providers post certain redispatch cost information associated with the
existing redispatch services that must be provided under the pro forma
OATT. The Commission concluded that providing customers with additional
transparency and greater information regarding the cost of congestion
will facilitate their consideration of planning redispatch options,
which in turn will provide for more efficient use of the grid. To that
end, the Commission directed each transmission provider to post on
OASIS its monthly average cost of redispatch for each internal
congested transmission facility or interface over which it provides
planning redispatch or reliability redispatch under the pro forma OATT.
In addition, to demonstrate the range of redispatch costs each month,
the Commission directed transmission providers to post a high and low
redispatch cost for the month for each of these same transmission
constraints.
621. Transmission providers must post internal constraint or
interface data for the month if any planning redispatch or reliability
redispatch is provided during the month, regardless of whether the
transmission customer is required to reimburse the transmission
provider for those exact costs. Thus, if the transmission customer pays
for planning redispatch pursuant to a negotiated fixed rate, the
transmission provider is required to post and calculate the monthly
average redispatch costs and the high and low costs in the month even
though the transmission provider will bill the customer the fixed rate.
The same posting requirement applies if the customer is paying a
monthly ``higher of'' rate. The Commission concluded that the relevant
reliability redispatch costs for posting purposes are those costs the
transmission provider invoices network customers based on a load ratio
share pursuant to section 33.3 of the pro forma OATT.\249\ The
transmission provider must post this data on OASIS as soon as practical
after the end of each month, but no later than when it sends invoices
to transmission customers for redispatch-related services. The
Commission directed transmission providers to work in conjunction with
NAESB to develop this new OASIS functionality and any necessary
business practice standards.
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\249\ Order No. 890 provided that the transmission provider need
not perform new calculations of out-of-merit redispatch costs;
rather the reliability redispatch invoices should form the basis of
information from which the transmission provider determines monthly
average reliability redispatch costs.
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Requests for Rehearing and Clarification
622. Ameren argues that the redispatch cost posting requirement is
unreasonable because it creates a substantial new burden for
transmission providers without creating offsetting benefits for
transmission customers. Ameren maintains that the Commission failed to
assess the benefits and the burdens of the redispatch costs posting
requirement. Ameren also maintains that this information will not
provide any value to the transmission customer in anticipating
redispatch costs since certain factors embedded in the calculation of
these costs, including fuel, will vary greatly over time. Ameren
concludes that existing requirements under the pro forma OATT are all
that is necessary to provide transparency for the service.
623. Progress Energy requests clarification that reliability
redispatch costs need only be posted if the transmission provider
invoices network customers for those costs. Progress Energy states that
Order No. 890 contains language that could be read to require the
posting of reliability redispatch costs even if network customers are
not invoiced for those costs, notwithstanding the Commission's
statement that the relevant reliability redispatch costs for posting
purposes are those costs the transmission provider invoices network
customers.\250\ Progress Energy concludes that it would be unduly
burdensome and serve no regulatory purpose to require transmission
providers to post reliability redispatch costs when they are not
invoicing their network customers for these costs.
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\250\ Citing Order No. 890 at P 1162, n.707.
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624. Entergy requests clarification that, when redispatch charges
are calculated and charged on a system average basis, only the average
costs for the system for the month need be posted. Entergy states that
its new weekly procurement process will provide customers a greater
opportunity to obtain transmission service by paying redispatch costs,
as determined through the optimization models in the weekly procurement
process. These optimization models will not calculate redispatch costs
for each specific constrained facility on Entergy's system.
[[Page 3060]]
Entergy states it would incur additional burdens if required to
separately calculate these costs to meet the Order No. 890 requirement
to post redispatch costs by each constrained facility.
Commission Determination
625. The Commission affirms the decision in Order No. 890 to
require transmission providers to post on OASIS monthly average
redispatch costs for each internal congested transmission facility and
interface over which planning redispatch or reliability dispatch are
provided under the pro forma OATT. We disagree with Ameren that this
creates a substantial new reporting burden for transmission providers.
The information to be posted is readily available to transmission
providers from the invoices used to charge network customers, in the
case of reliability redispatch costs, or calculations that the
transmission provider performs to bill for planning redispatch
services. The only added burden involves posting those previously
calculated costs and calculating averages in order to mask commercially
sensitive information. This additional averaging step was instituted to
address concerns raised by Ameren and others about release of
proprietary or confidential market information.\251\ Although we do not
believe this averaging step to be unduly burdensome, Ameren or any
other transmission provider may propose a variation from the pro forma
OATT to allow for posting of actual billing data if the transmission
provider believes it is too burdensome to average this data prior to
posting.
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\251\ See id. at P 1150.
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626. Any minimal burden imposed on transmission providers by the
redispatch cost posting requirement is offset by the benefits of
providing customers with fairly current information regarding which
facilities are congested each month and the average costs of redispatch
over those facilities.\252\ This information has previously been
provided only to customers receiving specific redispatch services.
While redispatch costs incurred by customers in the present do not
always correlate with future redispatch costs, a fact recognized by the
Commission in Order No. 890,\253\ more information on the currently
provided redispatch could be invaluable to a potential or current
customer evaluating different generation and transmission options. A
reporting requirement that allows customers to identify constraints and
the monthly average costs of relieving those constraints provides a
benefit to customers that outweighs the small monthly posting burden.
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\252\ See id. at P 1163.
\253\ See id. at P 1159.
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627. To the extent necessary, we clarify in response to Progress
Energy that transmission providers that do not calculate and charge
separate reliability dispatch charges to its network customers have no
obligation to report monthly redispatch costs for those services. The
posting obligations adopted in Order No. 890 were designed so that
transmission providers could post redispatch cost information based on
data already calculated for another purpose, including customer
invoices for reliability dispatch and the determination of charges for
the monthly ``higher of'' rate for planning redispatch.\254\ If
redispatch costs are calculated and charged on a system-wide basis
rather than for each constraint on the system, the transmission
provider has no obligation to perform new calculations to estimate the
redispatch costs for each constraint on its system. We therefore agree
with Entergy that, in the described situation, only the average costs
for the system for the month, including the highest and lowest system
average redispatch costs in an hour for the month, need be posted.
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\254\ The posting requirement for the newly instituted
negotiated fixed rate pricing option for planning redispatch is an
exception. If a transmission provider chooses to negotiate a fixed
rate for planning redispatch, it must determine and report the
redispatch costs for providing that service even though it might not
otherwise need to calculate these costs.
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d. Other Requested Service Modifications
628. The Commission rejected requests to adopt other new services
or modifications to existing services beyond those reforms adopted in
Order No. 890. Among other things, the Commission declined to require
transmission providers to offer a dynamic scheduling service for loads
and resources that are located in different transmission providers'
areas. The Commission stated that transmission providers seeking to
provide this or additional new services may submit an FPA section 205
filing to propose modifications to their OATT, which would be
considered on a case-by-case basis.
Requests for Rehearing and Clarification
629. TAPS requests that the Commission require transmission
providers to include provisions in their OATTs that would permit a
transmission dependent utility with loads and resources in multiple
control areas to consolidate them into a single control area via
dynamic scheduling. TAPS states that a control area utility with remote
generation and/or load has the option to use a pseudo-tie to import
generation into its control area. TAPS argues that transmission
dependent utilities should have comparable options priced at the
transmission provider's cost. TAPS contends that leaving transmission
dependent utilities in the position of having to negotiate with the
transmission providers for this option will leave them exposed to
unjust and unreasonable and unduly discriminatory imbalance pricing.
TAPS also argues that changes to the OATT to allow for dynamic
scheduling should not disturb already existing dynamic scheduling
agreements that have been successfully negotiated by transmission
dependent utilities.
Commission Determination
630. The Commission denies rehearing of the decision in Order No.
890 to not mandate a dynamic scheduling service in the pro forma OATT.
Dynamic schedules and pseudo-ties are both services that involve
metering, telemetry, computer software, hardware, communications,
engineering and administration. Each service is crafted to meet the
unique needs of each customer, typically requiring the cooperation and
services of at least two control areas as well as contractor-providers
of the components of the services. Comparability does not require the
transmission provider to undertake these negotiations on behalf of its
network customers. The unique, customer-specific nature of these
services are more properly arranged by negotiation between the relevant
parties rather than standardized in the pro forma OATT. However, to the
extent a transmission provider currently accepts telemetered generation
schedules for its native load, the transmission provider must accept
such schedules from its network customers on a comparable basis.
631. The Commission is also concerned that the mandatory cost-based
provision of pseudo-ties could allow transmission customers to cherry-
pick among transmission providers based on differences in service,
including ancillary service costs, and could cause insurmountable
planning and reliability problems for transmission providers. Under a
pseudo-tie, the control area receiving the new load or generation
signal assumes responsibility for ensuring that the load is properly
balanced moment-
[[Page 3061]]
to-moment, for planning for the load, and for providing various other
ancillary services including energy or generator balancing service. We
decline to impose unlimited planning, reliability and ancillary service
requirements on transmission providers by forcing them to accept any
load or generator that seeks to move to their systems. We are
encouraged, however, by the increased availability of pseudo-ties and
dynamic schedules in the industry. TAPS and others have been able to
secure dynamic scheduling agreements on a negotiated basis, and we do
not intend to disrupt those agreements in this proceeding.
2. Rollover Rights
632. In Order No. 890, the Commission revised the rollover
provision in section 2.2 of the pro forma OATT, which grants an ongoing
right to firm transmission customers to renew or ``rollover'' their
contracts. Under Order No. 888, transmission customers were allowed to
rollover contracts with a minimum term of one year, provided that they
provide notification of the rollover no later than 60 days prior to
expiration of their service agreements. The Commission concluded that
this provision was no longer just and reasonable, extending the minimum
term necessary to qualify for a rollover to five years and the notice
deadline to one year. Thus, a transmission customer must agree to
another five-year contract term or match any longer term competing
request within one year of expiration of its five-year service
agreement in order to be eligible for a subsequent rollover. The
Commission stated that this reform will become effective for each
transmission provider upon acceptance of the transmission provider's
compliance filing containing a coordinated and regional planning
process that satisfies the requirements of Order No. 890.
633. The Commission declined to eliminate the requirement that an
existing transmission customer match competing offers as to term and
rate in order to roll over its service. The Commission also continued
to require rollover restrictions to be based only on reasonable
forecasts of native load growth or preexisting contracts that commence
in the future. The Commission affirmed that any restrictions on a
customer's rollover rights must be included in the initial transmission
service agreement.
a. Five-Year Minimum Contract Term
Requests for Rehearing and Clarification
634. APPA, NCEMC, TAPS, and TDU Systems state a general concern
that, under current market conditions, some transmission customers may
be unable to obtain power supplies of a term and firmness required to
support a five-year firm transmission agreement. Each of these
petitioners note that FPA section 217(b)(4) requires the Commission to
exercise its authority ``in a manner that facilitates the planning and
expansion of transmission facilities to meet the reasonable needs of
load-serving entities to satisfy [their] service obligations * * * and
enables load-serving entities to secure firm transmission rights * * *
on a long-term basis for long-term power supply arrangements made, or
planned to meet such needs.'' These petitioners argue that the
Commission's rollover reforms impede, rather than facilitate, the
ability of LSEs to secure firm transmission rights on a long-term basis
to meet their service obligations.
635. TDU Systems and NCEMC suggest that implementation of the five-
year minimum contract requirement for obtaining rollover rights be
conditioned on a demonstration that the relevant generation markets can
support five-year power supply contracts. TDU Systems state that the
Commission misinterpreted its initial comments on this issue as a
request to require transmission providers to engage in the business of
procuring supplies for their transmission customers. TDU Systems
explain that they only requested that the Commission determine whether
market conditions are such that transmission customers themselves may
procure five-year generation contracts, such as by using the
Herfindahl-Hirshman Index as a tool for determining the competitiveness
of the relevant generation markets.
636. TAPS argues that, where transmission constraints exist, a
customer could be forced to remain with an incumbent supplier or face
the loss of its rights to continued use of the grid. NCEMC expresses
similar concerns, arguing that on constrained systems the rollover
reforms significantly increase the potential for market power abuse.
NCEMC contends that an incumbent generator can limit an LSE's access to
rollover rights by simply refusing to offer five-year power supply
contracts.
637. TAPS further argues that these concerns are not adequately
addressed by other reforms adopted in Order No. 890, as suggested by
the Commission. TAPS contends that many of these reforms, such as those
involving conditional firm and planning redispatch, redirects, and
capacity reassignment, apply only to point-to-point service, not
network service. TAPS argues that reforms increasing the accuracy of
ATC calculations will not help if the calculation results in zero ATC
and that coordinated transmission planning will only help if it results
in actual construction of transmission expansions. APPA similarly
argues that any benefits from increased coordination in transmission
planning will take some time to develop.
638. APPA and TAPS contend that the Commission should condition the
requirement of a five-year minimum contract term to obtain a rollover
right on allowing customers that enter into such contracts the
flexibility to modify receipt points and resource designations as their
power supply needs change. TAPS argues that the Commission should grant
certain clarifications regarding network customers' rollover rights, in
recognition of the fact that such customers pay for the transmission
provider's whole system. First, TAPS asks the Commission to make clear
that the customer is not restricted to its existing supplier by
requiring transmission providers to flexibly accommodate changed
resources so that network customers have the benefit of continued use
of the transmission system planned on their behalf and paid for on a
load ratio share basis. Second, TAPS asks the Commission, at a minimum,
to affirm the existing requirement that a new resource should not be
rejected as a rollover simply because it is not identical to the prior
resource, i.e., that a rollover must be allowed unless there is a
``substantial change'' in the direction of flows. Third, TAPS requests
that the Commission require the transmission provider, at least until
compliance with planning-related reforms, to accept a network
customer's timely designated network resource, even if necessary
through redispatch (with costs shared on a load ratio basis), unless
the transmission provider can show that the customer's supply choice
was not reasonably foreseeable. Alternatively, TAPS argues that the
Commission should require cost-based sales to the trapped embedded
transmission dependent utility.
639. TDU Systems state that rollover rights should be allowed
unless there is a substantial change in power flows and argues further
that transmission providers should be required to permit rollover of a
network customer's resource if the transmission provider would accord
itself rollover of the resource if it served the transmission
provider's load. TDU Systems argue that
[[Page 3062]]
transmission providers commonly treat their entire transmission systems
as single sinks and apply redispatch in order to accommodate rollover
of their own network resources, while at the same time, they evaluate
other users' rollovers of network resources non-comparably, strictly on
the basis of flows to discrete load centers, without the benefit of
redispatch. TDU Systems contend that this practice discriminates
against network customers. AMP-Ohio asks the Commission to clarify that
a network customer is permitted to roll over a portion of a long-term
reservation.
640. Morgan Stanley argues that the Commission failed to address
its argument that limiting rollover rights to customers with firm
transmission contracts of five years in length or more establishes
significant barriers to entry. Morgan Stanley contends the credit and
collateral requirements to enter into a five-year commitment are much
higher than those necessary to enter into a one-year deal and that this
higher credit requirement could limit the variety and flexibility of
the resources available to serve load. Morgan Stanley also argues that
extending the minimum term to five years will result in an increase in
transmission costs without any corresponding benefits to parties trying
to serve load. Morgan Stanley asserts that transmission customers
choosing to serve load will have to purchase more capacity than needed,
which will make less capacity available for others and will increase
costs to the loads served.
641. Morgan Stanley also argues that the change in rollover right
policy discriminates against merchant generators, like Morgan Stanley,
that do not have load linked to generation. Morgan Stanley contends
that forcing a merchant generator to purchase longer-term transmission
will increase its costs to build and encourage local utilities to build
their own generation rather than seek competitive alternatives. Morgan
Stanley repeats arguments that the lack of firm, long-term transmission
reservations in the California and New England organized markets belies
the Commission's findings that contract certainty is needed in order
for transmission providers to appropriately plan and construct their
systems.
642. Ameren similarly argues that the Commission failed to consider
the effect on the markets of limiting rollover rights to contracts with
a minimum term of five years, particularly with regard to markets in
which utilities meet their energy needs through annual auctions or
requests for proposals. Ameren contends that a one-year minimum term
should be all that is necessary for a customer to roll over its
service, arguing that current market conditions and the volatility in
fuel prices make it undesirable for power sellers and power purchasers
alike to enter into longer contracts. Ameren also questions the
Commission's argument that rollover reforms are needed to improve
transmission planning, arguing that the lack of transmission
infrastructure demonstrates that the prior rollover policy did not in
fact lead to overbuilding. Ameren asserts that there will be fewer
contracts with rollover rights under the new policy and, as a result,
planning and reliability will be harmed because transmission providers
will only have to plan for this more limited group of contracts. At the
same time, Ameren argues that the viability of the short-term market
will be impaired because the ability of transmission customers to
continue their service will be placed in doubt. Ameren contends that
this scenario will be exacerbated in organized markets where many sales
and purchases occur in short-term or spot markets. If the Commission
declines to grant rehearing regarding the five-year minimum term
requirement, Ameren asks the Commission to clarify that it is
eliminating the requirement for transmission providers to plan their
systems to accommodate transmission customers with contracts that are
shorter than five years.
643. Williams suggests that the minimum term for the exercise of
rollover rights should be three years, as it believes this better
balances the respective rights and obligations of transmission
customers and transmission providers. Williams argues that extending
the minimum rollover term will result in less flexibility for
transmission customers to adjust to changing market conditions and more
harm to competition. Williams provides an example of a customer
receiving non-firm service due to a redirected transmission service
request, asserting that the customer would be ``saddled'' with non-firm
service for the duration of the minimum term, notwithstanding the fact
that prior to the redirect the customer contracted for firm service.
Although the customer would still receive the same, non-firm service
under a three-year minimum term, the shorter term enables the customer
to return to the benefit of its bargain sooner and better reflects the
initial intent of the parties.
Commission Determination
644. The Commission affirms the decision in Order No. 890 to limit
rollover rights to contracts with a minimum term of five years. As the
Commission explained in Order No. 890, the prior rollover policy was no
longer just, reasonable, and not unduly discriminatory because the
rights and obligations of a rollover customer no longer bore a rational
relationship to the planning and construction obligations imposed on
the transmission provider by the rollover rights. We continue to
believe that a five-year term will ensure greater consistency between
the rights and obligations of customers and the corresponding planning
and construction obligations of transmission providers. While we
appreciate that this reform will affect the way customers retain
transmission service, other reforms adopted in Order No. 890 will
mitigate the concerns of shorter-term customers, in particular the
obligation for transmission providers to adopt an open, coordinated and
transparent process for planning to meet the transmission needs of all
customers.
645. The Commission takes seriously the concerns and allegations
about the presence of generation market power and the lack of
availability of long-term power contracts, and we will continue to
address these issues in other contexts, in particular our market-based
rate program. The purpose of our reform of the rollover policy,
however, is to align the rights and obligations of the customer with
those of the transmission provider, not with the availability of
supplies within a market or particular commercial practices in a
region. A point-to-point customer need not have a five-year power
contract in order to secure a five-year transmission service contract.
Similarly, it is the length of a network customer's network service
agreement, not the length of the power contract supporting a network
resource designation, that determines whether the customer is eligible
for rollover.\255\ Thus, the availability of five-year power contracts
is not determinative of the ability of transmission customers to obtain
rollover rights.
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\255\ See Wisconsin Pub. Power Inc. SYSTEM v. Wisconsin Pub.
Serv. Corp., 84 FERC ] 61,120 at 61,659 (1998) (WPPI).
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646. We acknowledge that entering into longer-term transmission
service agreements might increase risk or reduce flexibility for some
customers, including merchant generators, as they manage their power
supplies and transmission contracts. Balanced against this potentially
negative effect, however, are the many benefits that will flow from
rollover reform. Under the prior rollover policy, a customer could
secure transmission for one year and effectively require the
transmission provider to plan and upgrade its system on the
[[Page 3063]]
assumption the rollover right would be continually renewed. As the
Commission noted in Order No. 890, it is inappropriate to require
transmission providers to use finite resources to finance and construct
facilities that may not be necessary, particularly in light of the
difficulty of siting new transmission.\256\ The prior rollover policy
also harmed other transmission customers by allowing rollover customers
to lock up existing capacity that could have been used by other
customers. A minimum term of five years, and not a shorter period such
as three years as suggested by Williams, best balances the benefits and
burdens associated with our rollover policy.
---------------------------------------------------------------------------
\256\ See Order No. 890 at P 1233.
---------------------------------------------------------------------------
647. In response to TAPS, we clarify that we did not intend in
Order No. 890 to restrict the rollover right to exactly the same points
of receipt and delivery as the terminating service, as this would
competitively disadvantage existing customers seeking new sources of
generation. As the Commission explained in Order Nos. 888 and 888-A,
``if the customer chooses a new power supplier and this substantially
changes the location or direction of the power flows it imposes on the
transmission provider's system, the customer's right to continue taking
transmission service from its existing transmission provider may be
affected by transmission constraints associated with the change.''
\257\ Thus, a transmission provider must allow a rollover, even where a
transmission customer changes power suppliers, so long as there is no
substantial change in the location or direction of the power flows
imposed on the transmission provider's system. Moreover, we agree with
TDU Systems that it would be inappropriate for transmission providers
to treat a network customer's request for rollover to accommodate a new
designated network resource differently than they treat their own new
resources for their own loads. Transmission providers must permit
rollover of a network resource by another user if it would accord
itself rollover of the resource if it served the transmission
provider's load.
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\257\ See Order No. 888-A at 30,198, n.52 (citing Order No. 888
at 31,665, n.176).
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648. We do not believe, however, that it is appropriate to expand
the rights of rollover customers as requested by some petitioners. We
therefore decline to condition the requirement of a five-year minimum
contract term on allowing customers signing such agreements unlimited
flexibility to modify their designated resources and receipt points as
their power supply needs change within their five-year transmission
service agreements. As the Commission explained in Order No. 890, such
an approach is unworkable because it could result in substantial
disruptions in transmission service to higher queued customers
requesting long-term service over these paths.\258\ The fact that
network customers pay a load-ratio share of system costs does not
justify granting such customers a guaranteed ability to change their
service to other points without regard to other competing requests for
service that may be in the queue. Without a limit on rollover
customers' flexibility to modify designated resources and receipt
points, neither the transmission provider nor any other customer in the
queue would ever be able to rely on any study process for service, as
it could be thrown into disarray by a rollover customer seeking to
change its points. The only way such a system could work would be if
every transmission provider constructs its system with sufficient
redundancy to permit any customer to take service from any resource,
which would be both impractical and uneconomic.
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\258\ See Order No. 890 at P 1236.
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649. We also disagree that our reforms to rollover policy will harm
planning and reliability, even if it does result in fewer contracts
with rollover rights. As we note above, shorter-term transmission
customers no longer eligible for rollover rights will nonetheless have
access to the coordinated, open, and transparent transmission planning
process required in Order No. 890, which will help ensure that
transmission providers adequately and comparably plan for the
transmission needs of all of their customers whether or not they have
rollover rights. This is one of the reasons why the Commission
conditioned the effectiveness of the rollover reforms on its acceptance
of a transmission provider's Attachment K planning process in
compliance with the transmission planning principles adopted in Order
No. 890. By extending the minimum term for rollover rights, the
Commission simply relieved transmission providers of the obligation to
undertake construction on behalf of shorter-term customers that may not
ultimately need the facilities.
650. We reject the suggestion that a five-year minimum is
inconsistent with the requirements of FPA section 217. Limiting
rollover rights to contracts with a minimum term of five-years ensures
that the rollover right is used by customers with longer-term
obligations to purchase capacity, benefiting all longer-term customers
by limiting the ability of shorter-term customers to lock up capacity
they do not intend to use and facilitating efficient planning and
expansion decisions by the transmission provider. These benefits are
shared by the entire class of customers to which section 217 applies.
651. In response to AMP-Ohio, we clarify that both network
customers and point-to-point customers may roll over a portion of their
service, provided that they will only obtain a subsequent rollover
right if they agree to another five-year term, or match any longer term
competing request, for that portion of capacity.
b. One-Year Notice Provision
Requests for Rehearing and Clarification
652. Duke asks the Commission to further revise the rollover
notification provisions to provide for additional time for construction
of new facilities in the event project upgrades and lead times have
been identified. Duke argues that the Commission failed to explain in
Order No. 890 why it is reasonable to expect on-system LSEs, including
the transmission provider, to coordinate their resource plans with the
lead-time for new transmission facilities, but it is not reasonable to
expect off-system LSEs that rely upon point-to-point service to be
subject to the same realities. Because an LSE that is a network
customer on one system must provide sufficient and adequate notice for
its transmission provider to accommodate an on-system designated
network resource, Duke contends that the one-year notification
requirement for rollovers means that the same LSE need not provide a
neighboring transmission provider the same level of notice to
accommodate a point-to-point rollover request even if related to the
very same designated network resource. Duke further argues that the
Commission failed to explain why the native load protection rationale
that prompted adoption of the initial five-year eligibility provision
should not apply with equal force to the notification provision.
653. Duke states that, in its experience, most LSEs do not wait
until one year before the expiration of their contract resources to
make decisions as to a replacement resource. In the event an LSE does
choose to wait until one year before its current supply contract ends,
Duke argues that the LSE's decision should not disadvantage native load
and network customers if, as the Commission recognized, necessary
transmission upgrades cannot be completed within that one-year period.
Duke contends that modification of the
[[Page 3064]]
one-year notice requirement is necessary to ensure greater consistency
between the rights and obligations of customers and the corresponding
planning and construction obligations of transmission providers, the
stated goal of the Commission's rollover reforms. If the Commission is
unwilling to change the one-year notice provision, Duke suggests that
the Commission provide that a rollover customer's service will be
conditionally firm during the period prior to the point in time when
needed transmission upgrades can be completed.
654. Southern expresses a similar concern, arguing that a customer
should be required to provide notice of its intent to exercise its
rollover rights at the earlier of one year or the lead-time for any
construction of upgrades identified by the transmission provider in the
service agreement that are necessary in order to reliably exercise the
rollover right. Southern contends that this requirement would be
consistent with the ability of the transmission provider to place in
the original service agreement limits on the customer's ability to
exercise rollover rights and is needed to maintain reliability and
protect the provision of service to other firm users of the
transmission system, including native load.
Commission Determination
655. We affirm the decision in Order No. 890 to require customers
to notify the transmission provider of their intent to exercise their
rollover rights at least one year before expiration of their service
agreement. We reject requests to tie the notice period to the
construction lead-times for any upgrades a transmission provider may
believe are necessary in order to accommodate any rolled over service
along with its other service obligations. The Commission recognized in
Order No. 890 that the one-year notice period is shorter than the
typical planning horizon, but declined to extend the notice period to a
time that coincides with the typical planning horizon or the time it
takes to construct new facilities.\259\ The Commission balanced the
circumstances facing customers in renewing power supply contracts and
the interests of transmission providers in attempting to plan their
system. We continue to believe that the one-year notice provision most
appropriately balances these competing interests.
---------------------------------------------------------------------------
\259\ See id. at P 1247.
---------------------------------------------------------------------------
656. We acknowledge that, in certain circumstances, the one-year
notice period could cause the transmission provider to undertake
construction of facilities that are not ultimately needed to
accommodate other service obligations in light of a rollover customer
declining to rollover its service. However, moving from a 60-day notice
period to one year should mitigate the risk of unnecessary investments.
While allowing a transmission provider to require rollover notification
prior to construction of facilities (whether or not identified in the
original service agreement), or treating the customer's service as
conditionally firm while upgrades are completed, would further reduce
this risk for the transmission provider, it also would further decrease
flexibility for the transmission customer. As the Commission explained
in Order No. 890, no single notice period can perfectly balance the
needs of customers and transmission providers.\260\ The Commission
concluded that a one-year notice provision best balances the respective
benefits and burdens for customers and transmission providers, and we
affirm that decision here.
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\260\ See id. at P 1246.
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c. Matching Competing Requests
Requests for Rehearing and Clarification
657. APPA argues that the Commission's retention of its matching
policy, requiring transmission customers to match competing requests
for service as to term and rate, is inconsistent with FPA section
217(b)(4). In APPA's view, section 217(b)(4) requires the Commission to
exercise its FPA authorities to assist LSEs in meeting their service
obligations by securing firm transmission rights on a long-term basis.
APPA contends it is contrary to Congressional intent to require LSEs
that have made long-term financial commitments to the transmission
system, by entering into five-year agreements, to bid against all other
interested market participants in order to roll over their firm
transmission rights.
658. APPA also argues that the Commission's decision to lift the
price cap on reassignments of firm transmission capacity might
exacerbate the situation, as it could mean that LSEs will have to bid
against well-heeled financial players or marketing affiliates of the
transmission provider that may be bidding for the same capacity with
the sole intent of reassigning it at whatever price the market will
bear. APPA contends that this would require LSEs unable to match the
longer term offered (due, for example, to its inability to obtain a
power supply contract of that length) to have to obtain firm
transmission capacity in the reassignment market at a much higher rate.
APPA argues that this, too, is inconsistent with the Commission's
obligation under FPA section 217(b)(4) to enable LSEs with service
obligations to obtain the long-term firm transmission rights they must
have to meet those needs.
659. APPA adds that the transmission provider should have been
planning for the needs of firm transmission customers with contracts
that carry rollover rights throughout the term of the contract, since
the stated purpose of the rollover reform is to ensure that the rights
and obligations of the customer are better aligned with the planning
and construction obligations of the transmission provider. APPA argues
that capacity should therefore be available to meet the needs of firm
transmission customers seeking to exercise their rollover rights
without forcing them to ``bid on the margin'' for transmission capacity
every time their contracts come up for renewal.
660. TAPS proposes what it characterizes as safeguards to prevent
network customers exercising rollover rights from being significantly
disadvantaged by the obligation to match point-to-point reservations.
TAPS contends that a point-to-point customer, faced with a competing
longer-term reservation, can simply extend the term of its point-to-
point commitment to match the competing request. If the matching
process applies to network service designations under a network service
agreement (versus the service agreement itself), TAPS contends that the
network customer would need to extend its power supply commitment in
order to extend its transmission reservation to match the competing
request and would not be able to resell any transmission capacity for
which it could not find supplies. TAPS argues that this fails to
recognize and preserve the LSE's continuing rights under FPA section
217(b)(1) to (3) to use their existing firm transmission rights,
including rollover rights, and that it is inconsistent with section
217(b)(4) for the Commission to leave transmission-dependent LSEs at
risk of denial of continued use of transmission to meet their service
obligations.
661. TAPS therefore suggests that the Commission implement matching
based on the duration of a network customer's network service agreement
rather than its resource designation. Alternatively, if the Commission
concludes that the network customer must extend its resource commitment
(rather than just
[[Page 3065]]
its network agreement duration) to match a competing request, TAPS
proposes the following modifications to the process so that the network
customer is on a level playing field with competing point-to-point
customers in the matching process: restrict reservations qualified to
compete against a network customer's reservation to customers with
long-term power contracts (even if they seek only point-to-point
reservations); and provide a cut-off for competing requests that
accommodates the network customer's need to extend power supply
arrangements in order to match competing requests. TAPS suggests, for
example, that the network customer should only need to compete with
requests submitted at least three months prior to when the network
customer exercises its rollover right, which would allow the network
customer to structure its power supply commitments with some degree of
advanced knowledge of the competing requests. TAPS also suggests that
such a rolling cut-off (i.e., one tied to the network customer's
rollover notice) be adopted to encourage early exercise of rollover
rights, thereby benefiting the planning process.
662. TDU Systems suggest that the Commission cap the matching term
required to secure rollover rights to five years, arguing that a
customer agreeing to pay the maximum rate allowed under the tariff for
a five-year term should be assured that it will retain its rollover
rights. TDU Systems contend that the increase in the minimum term from
one year to five years has mitigated the need for an unlimited matching
requirement by providing the transmission provider greater certainty in
planning its system. TDU Systems also contend that transmission
providers will not be financially harmed by capping the matching
requirement at five years since competing rollover customers would be
subject to price-matching as well. Finally, TDU Systems argue that the
``longer of'' matching policy is unduly discriminatory when applied to
requests from transmission providers in particular, since they are able
to request transmission service for unreasonable terms that no
transmission customer could prudently match.
663. Ameren and Powerex propose other modifications to the matching
process. Ameren proposes that customers be required to provide notice
of a rollover within 15 days of a pre-confirmed competing request to
prevent the customer from sitting on capacity until the end of its
notice period. Powerex makes a related request to restrict the matching
requirement to bona fide competing commitments to take such service,
such as by requiring competing requests to be pre-confirmed or
requiring the execution of contingent service contracts. Powerex
contends that, without such a restriction, a customer wishing to roll
over its service could be required to match requests in the queue for a
longer duration that ultimately may not come to fruition. Powerex also
asks that the Commission clarify that, in cases where a long-term
customer that has exercised its rollover right is ``trumped'' by a
longer-duration competing request for a lesser quantity, the rollover
of the original request should be displaced only by the quantity needed
to fulfill the longer-term, lesser MW request. Powerex argues that no
commenter opposed this proposal and that the Commission did not provide
any rational basis for its rejection in Order No. 890.
Commission Determination
664. The Commission affirms the decision in Order No. 890 not to
eliminate the requirement to match competing requests in order to
retain rollover rights. Long-standing policy requires transmission
customers, at the time of rollover of their contracts, to match
competing requests for service as to term and rate. We disagree with
petitioners who claim that the requirement of a five-year minimum
contract term, or the terms of FPA section 217, necessitate any change
to our matching policy. The same rationale for the matching policy
articulated in Order No. 888 and its progeny with regard to the
original rollover right applies with equal force to the reformed
rollover right. That is, the matching policy provides a mechanism not
only for awarding capacity to those who value it most, but also for
breaking ties.\261\ We do not see how a change to a five-year minimum
contract term diminishes the need for, or the efficacy of, such a
mechanism.
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\261\ See Order No. 888-A at 30,197.
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665. As we noted in Order No. 890, absent the requirement that a
customer match the term of a competing request, transmission providers
could be forced to enter into shorter-term arrangements that could be
detrimental from both an operational standpoint, including system
planning, and a financial standpoint.\262\ While it is true that the
extension of the minimum rollover term from one to five years will
otherwise enhance the transmission provider's ability to fulfill its
planning and construction obligations, it does not follow that the
transmission provider should be required to forgo the operational and
financial certainty of an even longer-term competing request at the
time of a rollover. By awarding capacity to the customers that value it
the most, the matching requirement benefits all longer-term customers,
whether LSEs or other classes of customers, and is therefore fully
consistent with the requirements of FPA section 217.
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\262\ See Order No. 890 at P 1255 (citing Order No. 888-A at
30,197).
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666. We reiterate our existing policy that, in the event of
competing, mutually exclusive requests for network resource
designations, the network customer seeking rollover must match the term
of the competing network resource power contract.\263\ However, we
agree with TAPS that, given the differing nature and obligations of
network service versus point-to-point service, a network customer
seeking rollover of its network service for a designated resource
should be able to match a competing point-to-point request by extending
its network service agreement rather than the power contract supporting
the network resource designation.\264\ We also clarify, in response to
Powerex, that a customer exercising a rollover right is only required
to match a bona fide competing commitment to take service, evidenced
for example by a pre-confirmed transmission request or the execution of
a contingent service contract. We disagree with Ameren, however, that
the transmission provider should be permitted to effectively shorten
the customer's notice period by requiring the rollover customer to
match a competing request prior to the date by which its rollover
notice would otherwise be required.
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\263\ See WPPI 84 FERC at 61,655-56.
\264\ Any subsequent request to designate a network resource
would remain subject to the requirements of the pro forma OATT, as
with any other request to designate a network resource.
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667. With these clarifications, we continue to believe that it is
not unreasonable to require network customers to match competing
requests for their capacity, even if made by marketers in order to
engage in resales of capacity or by the transmission provider itself.
Matching ensures that the customers that value the capacity the most
are awarded the capacity. In any event, we believe it unlikely that a
network customer would be routinely faced with viable competing
requests from a point-to-point customer seeking service at the time of
the rollover because of the significant differences between network
transmission service (under which loads and resources are designated,
but not specific points of
[[Page 3066]]
receipt and delivery) and point-to-point service (under which such
points are required to be designated).
668. We disagree with APPA's suggestion that rollover customers
should be relieved of having to match competing requests because the
transmission provider is planning and upgrading its system on the
assumption that the rollover customer will continue service. The
matching requirement only arises if there are competing requests, i.e.,
notwithstanding any upgrades constructed or planned, capacity will not
be available to serve both the rollover customer and the competing
customer. If there is a bona fide request from a competing longer-term
customer, it is reasonable to expect the rollover customer to match the
request in order to ensure that capacity is awarded to the customer
that values it the most.
669. Finally, we further clarify in response to Powerex that, in
cases where a rollover customer loses service to a longer-duration
competing request for a lesser quantity, the rollover of the original
request should only be displaced by the quantity needed to fulfill the
longer-term request for a lesser quantity. In such instances, the
transmission provider should grant service to the competing customer
and reduce the amount of capacity available for roll over by the
original customer accordingly.
d. Rollover Restrictions Based on Native and Network Load Growth
Requests for Rehearing and Clarification
670. TDU Systems ask the Commission to eliminate the ability of
transmission providers to restrict other LSEs' rollover rights based on
forecasts of the transmission provider's retail and wholesale native
load growth. TDU Systems argue that extending the minimum term to
qualify for rollover rights effectively provides the transmission
provider five years of notice that it will need to construct
transmission upgrades to serve its native load growth. Thus, TDU
Systems contend, there is no justification for that transmission
provider to fail to build to meet its service obligation within this
period. TDU Systems further contend that permitting a transmission
provider to avoid its obligation to build for its known native load
growth by curtailing an LSE customer's rollover rights gives an undue
preference to the transmission provider's native load and violates the
Commission's comparability principle. TDU Systems argue this also
violates FPA section 217(b), which it contends does not distinguish
between the transmission provider's native load and the native load of
other LSEs.
671. If the Commission does not eliminate the ability of the
transmission provider to restrict rollover rights based on its own
forecasted load growth, TDU Systems ask, at a minimum, that the
Commission require transmission providers to treat the load growth of
other LSEs with native load service obligations in the same manner as
the transmission provider's own native load growth. NRECA makes a
similar request, arguing that comparability requirements and FPA
section 217 should place the service obligations of all LSEs on an
equal footing. NRECA asks the Commission to confirm that a transmission
customer using rollover rights to serve native load enjoys the same
priority as a transmission provider serving its own retail native load
and will be factored into any native load growth forecasts.
672. By contrast, South Carolina E&G and South Carolina Regulatory
Staff argue that the Commission should expand the ability of
transmission providers to restrict rollover rights. South Carolina
Regulatory Staff asks the Commission to ensure that native load growth
is not marginalized by new non-native customers. The South Carolina
Regulatory Staff expresses concern that native load service may be
forced to yield to other service if the transmission provider's native
load forecasts turn out to be wrong. South Carolina E&G agrees, arguing
that limiting the ability of transmission providers to restrict
rollover rights only in the initial service agreement puts service to
native load at an unreasonable risk. South Carolina E&G requests that
transmission providers be allowed to add rollover restrictions at the
time of each rollover (rather than only at the initiation of service)
to reflect changes in load growth forecasts.
673. Alternatively, South Carolina E&G suggests that the Commission
provide for a procedure that would allow the transmission provider to
terminate rollover rights when new facility construction is required
during system planning, i.e., at any point the transmission provider
determines that a new facility is necessary to accommodate a new
request or projected native load growth, given the possibility of full
rollover by eligible customers. South Carolina E&G proposes that
transmission providers be required to promptly give notice of that
determination, which would trigger a limited period of time (e.g., 30
days) for each long-term customer to indicate whether it desires to
rollover its current contract for another designated period of time.
Absent such election by the customer within the designated time, South
Carolina E&G proposes that the customer's rollover rights be
terminated. South Carolina E&G argues that this proposal would provide
at least partial protection against the inequitable prospect of being
forced to construct facilities that would be needed in the event of
full rollover of service, only to be left ``high and dry'' by a
customer's failure to exercise its rollover rights. South Carolina E&G
argues its alternative proposal would ensure that native load does not
subsidize the customer seeking rollover.
674. If the Commission declines to modify its rollover policies,
South Carolina E&G suggests the adoption of a native load curtailment
priority to ensure that continued service to the rollover candidate
does not impinge on native load service. Specifically, South Carolina
E&G states that point-to-point customers could receive rollover rights,
but if curtailment is required, then that rollover contract (like all
other point-to-point contracts) would be curtailed before native load.
South Carolina E&G also asks the Commission to provide greater
specificity regarding the meaning of the statement in Order No. 890
that, in forecasting native load growth, consideration should be given
to state-approved integrated resource plans that show a native load
need for the capacity. South Carolina E&G asks the Commission to
specify whether such a plan would be a determining factor in the
Commission's evaluation of a transmission provider's native load growth
forecast, how much weight the Commission would place on the existence
of such a plan, and whether the plan would need to incorporate specific
elements.
Commission Determination
675. The Commission continues to believe it is appropriate to
require that rollover restrictions be based on reasonable forecasts of
native load growth or preexisting contracts that commence in the future
and that such restrictions be included in the initial transmission
service agreement. As explained in Order No. 890, this will remain the
only appropriate way to restrict a rollover right.\265\ We are not
persuaded by petitioners' arguments that the requirement of a five-year
minimum contract term, or the native load protections found in FPA
section 217, necessitates any change to this policy. The same rationale
for this policy articulated in Order No. 888 and its progeny with
regard to the original
[[Page 3067]]
rollover right applies with equal force to the reformed rollover
right.\266\
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\265\ See Order No. 890 at P 1256.
\266\ See Order No. 888 at 31,694; Order No. 888-A at 30,198.
---------------------------------------------------------------------------
676. We disagree with TDU Systems that extending the minimum term
to five years justifies eliminating the ability of the transmission
provider to restrict a customer's rollover right. The transmission
provider is allowed to restrict a rollover right in favor of its
reasonably forecasted native load growth in order to ensure that
capacity that exists on the provider's system, at the time of entering
into a contract with a customer seeking a rollover right, can be
recalled for the use of its reasonably forecasted native load growth at
some time in the future. Our longstanding policy, which was not changed
by Order No. 890, permits transmission providers to reserve existing
capacity for the use of its reasonably forecasted native load growth.
677. Arguments that the transmission provider has more time to plan
for upgrades to meet its native load growth because of the new five-
year minimum contract term miss the point. A transmission provider
should not be forced to allow rollover where, at the time of entering
into a five-year transmission contract with a customer for existing
capacity, it can show that it will need to reclaim that capacity to
serve its reasonably forecasted native load growth. Customers that are
denied rollover rights may nonetheless secure transmission service by
submitting service requests for the period in question and committing
to fund any necessary upgrades.
678. Alternatively, TDU Systems and NRECA ask the Commission to
require transmission providers to treat the load growth of other LSEs
with native load service obligations in the same manner as the
transmission provider's own native load growth during forecasting. This
is already our policy. In Order No. 888-B, the Commission, in
addressing a transmission provider's ability to recall capacity needed
for native load growth, clarified that ``network transmission customers
are afforded the same treatment as the transmission provider on behalf
of native load (retail and wholesale requirements customers) in terms
of the reservation of existing transmission capacity by the
transmission provider.'' \267\ This ensures that the LSE's native load
is treated the same as the transmission provider's native load at the
time a rollover restriction is considered.
---------------------------------------------------------------------------
\267\ See Order No. 888-B at 62,084-85.
---------------------------------------------------------------------------
679. We reject the argument of South Carolina E&G and South
Carolina Regulatory Staff that the Commission should expand the ability
of transmission providers to restrict rollover rights by, for example,
allowing rollover restrictions to be added at the time of each rollover
(rather than only at the initiation of service) or when the need for
new facilities arises. We continue to believe that requiring
transmission providers to determine at the initiation of service
whether they have a reasonably forecasted native load growth need for
the capacity strikes a reasonable balance between the transmission
provider's needs and those of its customers seeking long-term
transmission service with a rollover right.\268\ If we were to allow
the transmission provider the ability to seek to restrict a rollover at
the time of each rollover, as suggested by South Carolina E&G, it would
vitiate the benefit of the rollover right to transmission customers,
many of which also have load-serving obligations. We note, however,
that South Carolina E&G's concerns should be mitigated going forward
since our requirement of a five-year minimum contract term, as well as
the one-year notice period and the other rollover reforms, will ensure
greater consistency between the rights and obligations of customers and
the planning and construction obligations of transmission providers.
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\268\ In addition, we believe that putting the onus on the
transmission provider to determine the limitations of its system and
its own native load growth needs at the time of the initial service
agreement appropriately allocates responsibility and encourages
accuracy. Allowing transmission providers the ability to reevaluate
their native load growth needs on an ongoing basis, or to escape
obligations to serve rollover customers when upgrades are
identified, would tend to discourage a thorough review upfront.
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680. We also decline to adopt South Carolina E&G's suggestion that
point-to-point customers with rollover rights be curtailed before
native load. The Commission has long required that firm point-to-point
customers share the same curtailment priority as network customers and
the transmission provider serving native load except in the limited
circumstance when it would require the shedding of bundled retail
load.\269\ Nothing in our changes to rollover policies justifies
modifying that requirement. We also decline to determine generically
the weight to be given to state-approved integrated resource plans in
the determination of reasonable native load restrictions. The
determinative factors in each case will be identified based on the
record, along with the relevant particular supporting documentation to
be considered.
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\269\ See Northern States Power Co., 89 FERC ] 61,178 (1999).
---------------------------------------------------------------------------
e. Effectiveness Upon Acceptance of Coordinated and Regional Planning
Process
Requests for Rehearing and Clarification
681. Duke argues that the rollover reforms should be implemented
immediately and not upon acceptance of the transmission provider's
planning process compliance filing. Duke contends that the Commission
unambiguously found that the prior rollover policy was no longer just
and reasonable and not unduly discriminatory. Duke also argues that the
prior rollover policy is inconsistent with FPA section 217, suggesting
that the prior policy conflicts with the reasonable needs of LSEs to
satisfy their service obligations. Duke therefore argues that it is not
reasonable for the Commission to allow its prior rollover policies to
remain in place pending acceptance of the transmission planning process
compliance filings. Duke contends that the Commission did not base its
finding that rollover policies were in need of reform on the lack of
transmission planning processes and, therefore, making one conditioned
on the other is unsupported.
682. TAPS requests clarification of the timing of compliance
filings implementing the new rollover policies. TAPS questions whether
transmission providers were required to submit conforming changes to
section 2.2 in their initial compliance filings or as part of the
Attachment K compliance filings due at a later date. If the former,
TAPS states that transmission providers would be deleting the current
language that will still be in effect. TAPS suggests that changes to
section 2.2 not be made until the Attachment K is accepted.
Commission Determination
683. The Commission denies rehearing of the determination to tie
the effectiveness of rollover reform to the acceptance of the
transmission provider's coordinated and regional planning process
required under Order No. 890. As the Commission explained in Order No.
890, reforms regarding rollovers and transmission planning must proceed
together because they are closely related. Under our longstanding
policy, transmission service eligible for a rollover right must be set
aside for rollover customers and included in transmission planning.
Duke is therefore incorrect in suggesting that the Commission did not
rely on our planning-related reforms when fashioning a remedy to ensure
rollover
[[Page 3068]]
policies remain just and reasonable and not unduly discriminatory.
684. With regard to TAPS' concern regarding the timing of
compliance filings implementing the new rollover policies, we reiterate
that the previously existing rollover provisions will remain in effect
for the transmission provider until such time as the Commission accepts
the transmission provider's Attachment K compliance filing.
Accordingly, it is only after a transmission provider's Attachment K
planning process is accepted by the Commission that the transmission
provider should file the rollover reform language, and the effective
date of that language should be commensurate with the date of that
filing. We have revised section 2.2 of the pro forma OATT to make this
clear.
f. Transition Issues
Requests for Rehearing and Clarification
685. Great Northern seeks clarification, or in the alternative
rehearing, regarding how rollover reform would apply to transmission
service requests that were made before the issuance of Order No. 890 in
reliance on the prior version of section 2.2 of the pro forma OATT. If
Order No. 890 is implemented in such a way as to require a minimum
five-year contract term in order for rollover rights to attach to
pending transmission service requests, Great Northern contends it would
cause significant disruption in the development and financing of
competitive generation projects already in the queue. Great Northern
suggests that requiring pending projects to submit new contracts for
five-year terms in order to obtain rollover rights in turn would
require it to restart its project planning process for each of those
projects.
686. Great Northern therefore asks the Commission to confirm that
the current one-year contract commitment right of first refusal rule
will continue to apply to transmission service requests that were made
prior to the issuance of Order No. 890 and that the five-year contract
commitment right of first refusal rule will not apply until the first
rollover date after both the executed transmission service contract and
revised section 2.2 of the transmission provider's pro forma OATT have
become effective. If the Commission is not inclined to make such a
generalized determination in this proceeding, Great Northern requests
the Commission to rule that, in the specific circumstances where a
customer has requested transmission service for one year with rollover
rights as described in section 2.2 of the OATT, and thus the
transmission provider was on notice of the potential need to exercise
rollover rights, it will allow rollover rights to apply until the first
rollover date after both the executed transmission service contract and
revised section 2.2 of the transmission provider's OATT have become
effective.
687. NCEMC, NRECA, and TDU Systems request that the Commission
clarify that a transmission customer will be permitted to rollover an
existing contract one time at the current terms and conditions
following the effective date of Order No. 890, as this would avoid any
impairment of the contracts entered into by parties prior to the
Commission's change in rollover rights policy, consistent with Mobile-
Sierra requirements.\270\ By granting one rollover with the same terms
and conditions following the effective date of Order No. 890, these
petitioners assert that the Commission will permit the parties to
fulfill all obligations under their previously-negotiated transmission
contracts and then, following this rollover, enter into new
transmission and power supply contracts with full knowledge of the
Commission's new rollover policy. They contend that certain preamble
language could be understood to permit a customer to rollover a
contract one time at the currently-effective terms and conditions
following the effectiveness of the rollover reforms,\271\ whereas
reformed section 2.2 suggests that the five-year term requirement and
notice provision will become effective on the first rollover following
effectiveness of the rollover reforms.\272\
---------------------------------------------------------------------------
\270\ Citing United Gas Pipe Line Co. v. Mobile Gas Services
Corp., 350 U.S. 332 (1956); Federal Power Commission v. Sierra
Pacific Power Co., 350 U.S. 348 (1956).
\271\ Citing Order No. 890 at P 1238 (``existing transmission
contracts will be permitted to roll over under their existing terms
until the first such rollover opportunity following the
effectiveness of the reforms required by this Final Rule.'').
\272\ Citing reformed section 2.2 (``[s]ervice agreements
subject to a right of first refusal entered into prior to [the
acceptance by the Commission of the Transmission Provider's
Attachment K], unless terminated, will become subject to the five-
year/one-year requirement on the first rollover date after [the
acceptance by the Commission of the Transmission Provider's
Attachment K].'').
---------------------------------------------------------------------------
688. TAPS contends that there could be confusion stemming from the
language in the Order No. 890 version of section 2.2, which states that
the ``five-year/one-year requirement'' will apply ``on the first
rollover date'' after Attachment K is accepted. TAPS believes this
language could be read to require that a customer's first rollover
after the effective date of Attachment K must be exercised one year
prior to the end of the existing service agreement, which is at odds
with the Commission's recognition that some contracts may not have a
year left on them and therefore the 60-day notice should apply to such
contracts.\273\ TAPS suggests specific amendments to section 2.2 of the
pro forma OATT to more clearly state the process for rolling over
service during the transition period.
---------------------------------------------------------------------------
\273\ Citing Order No. 890 at P 1267.
---------------------------------------------------------------------------
689. Powerex also asks that section 2.2 be amended to more clearly
state the Commission's rollover policies, arguing that discriminatory
and anticompetitive practices are more likely to occur in areas where
the transmission provider retains discretion. Powerex suggests that the
Commission clarify that customers with existing long-term contracts
with rollover rights must only provide 60-days prior notice of their
desire to roll over their capacity and that the rollover may be for a
one-year term with no rollover rights or a five-year term with rollover
rights. TransServ, however, argues that the modified notice
requirements of section 2.2 should apply only to existing long-term
agreements set to expire within one or two years of the effective date
of the new five-year/one-year long-term service requirements. TranServ
argues that allowing existing customers with longer-term contracts to
retain a 60-day notice provision for many years into the future would
unnecessarily complicate and delay the transmission provider's ultimate
conversion of all existing service agreements to comply with the new
five-year/one-year provisions for long-term firm service.
690. Ameren and Tenaska ask the Commission to clarify that notice
of a rollover given prior to the effectiveness of rollover reform would
remain subject to the pre-Order No. 890 rollover polices, including the
existing customer's willingness to accept a term of one year (or the
term offered by a competing applicant, if longer).
Commission Determination
691. We agree with Great Northern that requiring a five-year
minimum contract term in order for rollover rights to attach to pending
transmission service requests could cause significant disruption to
those transmission customers already in the transmission queue at the
time of the effective date of Order No. 890. These customers requested
service believing that they only needed to enter into a one-year
contract in order to obtain a rollover right. Accordingly, we grant
rehearing and revise section 2.2 of the pro forma OATT to provide that
the current one-
[[Page 3069]]
year contract commitment requirement will continue to apply to all
transmission service requests that were in a transmission provider's
transmission queue as of the effective date of the reforms adopted in
Order No. 890 (i.e., July 13, 2007). For such transmission requests,
the five-year contract commitment requirement will not apply until the
first rollover date after both the execution of the transmission
service contract and effectiveness of the revised section 2.2 for the
particular transmission provider.
692. We disagree with other petitioners, however, that a
transmission customer should be permitted to roll over any other
existing contracts one time at the current terms and conditions
following the effective date of the rollover reforms. As we explained
in Order No. 890, ``[i]t is only a rollover contract entered into or
renewed after the effectiveness of rollover reform that must comply
with the new rollover provisions.'' \274\ While it is true that the
customer rolling over service after the effectiveness of the reforms
will be required to agree to a minimum five-year term to obtain
rollover rights for the new agreement, this does not impair the
customer's rights or obligations under its existing contract.
---------------------------------------------------------------------------
\274\ See id.
---------------------------------------------------------------------------
693. To the extent there is any confusion regarding the discussion
in Order No. 890 of when the rollover reforms apply to existing
customers, we clarify that an existing customer must comply with the
new rollover reforms at the time of the first rollover of its contract
occurring after the effectiveness of the rollover reforms for its
transmission provider, as provided in the revisions to section 2.2 of
the pro forma OATT. For example, if an existing customer's contract
expires January 1, 2009, and rollover reform became effective on
January 1, 2008 for its transmission provider, then any contract
entered into by the customer at the time of expiration of its existing
contract on January 1, 2009 would have to comply with the rollover
reforms (e.g., the new contract must be for a minimum term of five
years to retain a rollover right and, if so, one-year notice must be
given to exercise that right at the expiration of the contract).
694. In response to TAPS and Powerex, we reiterate that a
transmission customer with an existing contract that seeks to exercise
its rollover after the effectiveness of rollover reform may exercise
this rollover based on the existing 60-day notice rule, in recognition
of the fact that during this transition period certain customers may
not have a year or more left on their existing contracts.\275\ We
agree, however, with TranServ that allowing existing customers with
longer-term contracts to retain a 60-day notice period provision for
many years in the future would unnecessarily complicate and delay the
transition to rollover reform. Allowing existing customers to utilize
the 60-day notice rule was intended largely to address the situation
where a given customer does not have a year or more left on its
contract such that it is possible to give one-year notice. This, of
course, is not the case with existing contracts that have many years
left in their terms before expiration.
---------------------------------------------------------------------------
\275\ See id.
---------------------------------------------------------------------------
695. We therefore clarify that the current 60-day notice rule will
continue to apply only to those existing contracts that have less than
five years left in their terms at the time of effectiveness of rollover
reform for its transmission provider. Any customer with an existing
contract with five or more years left in its term at the time of
effectiveness of rollover reform for its transmission provider will be
required to give one-year notice of whether it intends to exercise its
rollover right. We emphasize that, whether an existing transmission
customer is required to give 60-days or one-year notice when exercising
its rollover right under its existing contract, the customer must enter
into a minimum of five years of service and meet any of the other
requirements of the reformed rollover right in order to retain a
rollover right going forward. An existing customer may rollover its
service for a term of less than five years, but will not then retain a
rollover right for this service. We revise section 2.2 of the pro forma
OATT to make these requirements clear.
696. In response to Ameren and Tenaska, we reiterate that notice of
a rollover given prior to the effectiveness of rollover reform remains
subject to the pre-Order No. 890 rollover policies, including the
existing customer's willingness to accept a term of one year (or the
term offered by a competing applicant, if longer).\276\
---------------------------------------------------------------------------
\276\ See id. at P 1238 (``existing transmission contracts will
be permitted to roll over under their existing terms until the first
such rollover opportunity following the effectiveness of the reforms
required by this Final Rule.'').
---------------------------------------------------------------------------
3. Modification of Receipt or Delivery Points
697. Pursuant to Section 22 of the pro forma OATT, a transmission
customer taking firm point-to-point service may modify its receipt and
delivery points, i.e., redirect its service, on either a non-firm or
firm basis. In Order No. 676, the Commission adopted the ``Standards
for Business Practices and Communication Protocols for Public
Utilities'' developed by the NAESB's Wholesale Electric Quadrant
(WEQ).\277\ The WEQ standards include standards addressing requirements
for redirects on both a firm and non-firm basis, all of which were
incorporated by reference into the Commission's regulations except for
WEQ Standard 001-9.7, which addressed the impact of redirects on the
rollover rights of a long-term transmission customer. Order No. 676
directed the WEQ to reconsider WEQ Standard 001-9.7 and develop a
revised standard consistent with Commission policy.
---------------------------------------------------------------------------
\277\ Standards for Business Practices and Communication
Protocols for Public Utilities, Order No. 676, 71 FR 26199 (May 4,
2006), FERC Stats. & Regs. ] 31,216 (2006), reh'g denied, Order No.
676-A, 116 FERC ] 61,255 (2006), order on reh'g, Order No. 676-B, 72
FR 21095 (Apr. 30, 2007), FERC Stats. & Regs. ] 31,246 (2007).
---------------------------------------------------------------------------
698. In Order No. 890, the Commission affirmed reliance on the
NAESB process to develop business practices implementing the
Commission's redirect policy. The Commission also determined that the
reforms adopted in Order No. 676, in combination with the OATT-related
reforms adopted in this proceeding, were adequate to ensure that
transmission providers do not engage in undue discrimination when a
customer seeks to modify its receipt and delivery points on a firm
basis. With respect to the effect of redirects on rollover rights, the
Commission affirmed its policy allowing a redirect of firm, long-term
service to retain rollover rights, even if the redirect is requested
for a shorter period. The Commission concluded that a transmission
customer should not have to choose between maintaining its rollover
rights and redirecting on a firm basis. The Commission noted, however,
that any change to a delivery point would be treated as a new request
for service for purposes of determining availability of capacity. As a
result, a redirect right does not grant the customer access to system
capacity or queue position different from other customers submitting
new requests for service. The Commission also provided guidance
regarding the processing of, and pricing for, redirected service.
Requests for Rehearing and Clarification
699. MISO seeks rehearing of the Commission's decision to allow
rollover rights to follow the redirected service, asking that rollover
rights be limited or eliminated altogether in the event of a
[[Page 3070]]
redirect. MISO argues that the Commission's statement that it was
simply continuing its existing rollover policy is confusing since the
Commission found that the current rollover policy was no longer just
and reasonable. MISO also contends that the precedent cited by the
Commission does not support migration of rollover rights to a
redirected path. Even if the rollover policy were justified under the
Commission's precedent, MISO argues that the Commission's finding that
the policy is no longer just and reasonable undermines continued
reliance on that precedent.
700. If the Commission decides to maintain rollover rights for
redirects, MISO proposes the following limitations and requests the
Commission to direct NAESB to draft its business practices accordingly.
First, MISO suggests that the primary path agreement should have a term
of at least five years for any rollover rights to attach. Second, MISO
requests that any redirect must be for firm service for one year or
longer. If the redirect is for a shorter period, MISO contends that the
rollover rights should remain with the original path. Third, MISO
requests redirected service to terminate on the same date as the parent
service so as to maintain the timing for execution of rollover rights.
Finally, MISO suggests that in order to execute a rollover right the
redirected service must be requested and granted prior to the one-year
deadline for the customer to request rollovers along the original path.
701. Bonneville requests a similar clarification of the application
of rollover rights to redirects. Bonneville argues that a literal
reading of the revised pro forma OATT allows a long-term point-to-point
customer to request redirected service within the last year of its
service contract, maintain its rollover rights, and apply them to the
new points even though it is unable to give a year's notice of intent
to rollover at those points. Bonneville therefore seeks clarification
from the Commission that rollover rights will remain with the original
points unless the customer redirects service for at least one year.
Without clarification, Bonneville contends that redirecting customers
will have greater rights than customers that do not redirect, who must
give one-year's notice.
702. TranServ also requests clarification regarding the requirement
for the rollover right to follow the redirect, regardless of the
duration of the redirect. TranServ questions whether a redirect of a
long-term firm service reservation for one day qualifies that customer
for rollover rights on the redirected service points. TranServ suggests
that the Commission instead restrict rollover rights on redirected
service points to redirects of five years or longer and further require
that the redirect be co-terminus with the original request being
redirected. TranServ argues that more guidance regarding implementation
of the rollover and redirect policies will facilitate the NAESB
standards development process.
703. MidAmerican requests clarification regarding the queuing of
service requests as applied to redirects. MidAmerican argues that a
request to redirect service should not result in a release of transfer
capability for third-party service requests in the queue, since the
increase in transfer capability is contingent upon the approval of the
redirect request. MidAmerican argues that this approach is consistent
with the requirement in section 17 of the pro forma OATT to use the
``same system assumptions and analysis applicable to any other new
request for service, including whether sufficient ATC exists,'' when
analyzing the ability to grant a request for redirected service.
Commission Determination
704. The Commission denies petitioners' requests to amend the
rights of rollover customers to redirect their service. Under section
22.2 of the pro forma OATT, a request for a firm redirect must be
treated like a request for new transmission service.\278\ As a new
request for service, each redirect request is subject to the
availability of capacity and subject to the possibility that the
transmission provider may not be able to provide rollover rights on the
new redirected path. The transmission provider is required to offer
rollover rights to a customer requesting a firm redirect only if
rollover rights are available on the redirected path, i.e., to the
extent not restricted based on reasonable forecasts of native load
growth or preexisting contracts that commence in the future.\279\
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\278\ See Order No. 890 at P 1268.
\279\ See Order No. 676 at P 51.
---------------------------------------------------------------------------
705. As the Commission explained in Order No. 890, rollover rights
follow the redirect regardless of the duration of the redirect.\280\ A
transmission customer making a firm redirect request does not convert
its original long-term firm transmission service agreement into two
short-term service agreements, nor does it lose its rollover rights
under its long-term firm transmission service agreement.\281\ At the
same time, a customer can exercise its rollover right only at the end
of the contract. Thus, if a customer with rollover rights chooses to
redirect its capacity for less than the full remaining term of the
contract, absent some further request to redirect, the original path
will automatically be reinstated and rollover rights would remain on
only the original path. By contrast, if the customer chooses to
redirect its capacity until the end of its contract, the customer would
have rollover rights along only the redirected path, and only to the
extent not restricted based on native load growth or future contracts
along the redirected path.
---------------------------------------------------------------------------
\280\ Order No. 890 at P 1280.
\281\ Id.; see also Commonwealth Edison Co., 95 FERC ] 61,027 at
61,083 (2001) (explaining that a request to change delivery points
on a firm basis for one month, followed by a reversion to the
original points does not convert the existing long-term firm
agreement into two separate short-term agreements); American
Electric Power Service Corp., 97 FERC ] 61,207 at 61,905-06 (2001).
---------------------------------------------------------------------------
706. We therefore reject requests to restrict rollover rights to
longer-term redirects. A long-term transmission customer may request
multiple, successive redirects for firm service. This discretion is
limited by the fact that each successive request is treated as a new
request for service in accordance with section 17 of the pro forma
OATT. Each request is therefore subject to the availability of capacity
and subject to the possibility that the transmission provider may not
be able to provide rollover rights on the new, redirected path.\282\ If
the customer has not been granted rollover rights for a redirect that
extends to the end of its contract, the redirected service will
terminate on the same date as the parent service.
---------------------------------------------------------------------------
\282\ For example, assume a transmission customer with a five-
year agreement for firm service between points A and B, who
qualifies for rollover rights on that path. If the transmission
customer seeks to redirect on a firm basis in year 3 to points C to
D and then redirect back to points A and B thereafter, at the end of
the five year agreement the transmission customer would have
rollover rights only with respect to points A to B. If, however, the
transmission customer seeks to redirect to points C and D for the
last six months of the contract term and both qualifies for rollover
rights on this path and has requested rollover within the notice
period of the contract, the customer would then have rollover rights
only with respect to points C and D. See Order No. 676 at P 59.
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707. We also reiterate that a customer cannot exercise any rollover
rights unless it first has provided the appropriate notice to the
transmission provider. If a customer requests and is granted a rollover
right prior to the relevant notice deadline (60 days for pre-Order No.
890 agreements or one year for all others) and subsequently requests
and is granted a redirect for firm service for the remainder of the
contract term (i.e., within the notice period), the new reservation
governs the rights at the new receipt and delivery
[[Page 3071]]
points and the customer can obtain rollover rights with respect to the
redirected capacity to the extent rollover rights are available for the
redirected points. If, however, a customer fails to request a rollover
right prior to the relevant notice deadline, the customer forfeits
rollover rights along the current or any redirected path.
708. We clarify, to the extent necessary, that transfer capability
is not freed up for earlier queued service requests until a redirect
has been granted. A redirect request must be evaluated in accordance
with section 17 of the pro forma OATT using the same system assumptions
and analysis applicable to any other new request for service, including
whether sufficient ATC exists to accommodate the request.\283\ If there
is insufficient ATC to offer service to customers in the queue, and an
existing customer requests redirected service, any increase in ATC
along the original path is contingent upon the acceptance and
confirmation of the redirect. It cannot be assumed at the time of a
redirect request that the transmission provider will grant the request.
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\283\ Order No. 890 at P 1285.
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4. Acquisition of Transmission Service
a. Processing of Service Requests
(1) Posting Performance Metrics
709. To enhance the transparency of the study process and shed
light on whether transmission providers are processing studies in a
timely and non-discriminatory manner, Order No. 890 required all
transmission providers, including RTOs and ISOs, to post on their OASIS
sites certain metrics that track their performance in processing system
impact studies and facilities studies associated with requests for
transmission service. Specifically, the Commission required all
transmission providers to post on a quarterly basis performance metrics
associated with: processing time from initial service requests to the
offer of a system impact study; system impact study processing time;
service requests withdrawn from the system impact study queue;
processing delays for system impact studies caused by transmission
customer actions; processing time from completed system impact study to
the offer of a facilities study; facilities study processing time;
service requests withdrawn from the facilities study queue; and,
processing delays for facilities studies caused by transmission
customer actions. The Commission required transmission providers to
begin tracking these performance metrics upon the effective date of
Order No. 890 and keep the quarterly performance metrics posted on
their OASIS sites for three calendar years.
710. The Commission also required transmission providers, including
RTOs and ISOs, to submit a notification filing to the Commission in the
event the transmission provider processes more than 20 percent of non-
affiliates' studies outside of the 60-day due diligence deadlines in
the pro forma OATT for two consecutive quarters. The transmission
provider may explain in its notification filing that it believes there
are extenuating circumstances that prevented it from meeting the
deadlines in the pro forma OATT. Absent a determination from the
Commission that delays were due to extenuating circumstances, the
transmission provider is required to post additional metrics regarding
the average number of hours expended on, and the number of employees
dedicated to, system impact studies and facilities studies. Unless
otherwise directed by the Commission, the transmission provider must
begin posting the additional performance metrics the quarter following
the notification filing.
711. The Commission delegated to NAESB the responsibility for
developing the Standard and Communications Protocols, business
practices and OASIS modifications that will be necessary to implement
the performance metrics.
Requests for Rehearing and Clarification
712. Two transmission providers object to aspects of the standard
performance metric posting requirements. Ameren objects to the
requirement that RTOs post these metrics, arguing that the requirement
may increase an RTO's cost even though it is unnecessary for the
efficient operation of competitive markets. Ameren argues that RTOs are
by definition independent entities that lack the incentive to favor any
transmission customer over another and, therefore, the performance
metrics will serve no purpose in uncovering potential discrimination in
the study request process. Ameren argues that information already
posted by MISO and other RTOs allows the Commission to obtain the data
it seeks without placing additional requirements on RTOs.
713. Old Dominion argues that the Commission should include in the
standard performance metrics any denials or delays in the construction
phase of transmission service requests, suggesting that review of
whether requested transmission service is effected through construction
of identified upgrades and other facilities is a logical and necessary
outgrowth of Order No. 890.\284\ Old Dominion asks the Commission to
require transmission providers to add to the standard performance
metrics: the time period of any such postponement or delay; the MW
amount of congestion caused by the delay, if any; the amount of
transmission rights underfunding caused by the delay, if any; and,
whether the delay resulted in any degradation of system reliability.
Old Dominion contends that the progress of each project is essential
for transmission providers to determine whether transmission service
requests can be accommodated and whether a transmission project is
actually constructed or not has an effect on the study process for
subsequent projects in the queue.
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\284\ Old Dominion also argues that the Commission should
require performance reports regarding transmission planning
activities, which the Commission addresses in section III.B.
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714. Other transmission providers object to the aspects of the
additional performance metrics triggered by consistently processing
studies outside the 60-day due diligence deadline. Washington IOUs ask
that the Commission require transmission providers to post information
on employees and employee-hours devoted to study processing only if the
Commission first determines that delays in processing study requests
are not excused by extenuating circumstances. Washington IOUs contend
that the Commission's requirement, in Order No. 890, to calculate and
post this additional information will create a significant additional
burden and fails to recognize that the 60-day window is a target, not a
deadline. They further contend that customers may ask that additional
time be taken in the processing of studies. Absent a determination that
delays in processing study requests are a result of a lack of good
faith and due diligence on the part of the transmission provider,
Washington IOUs argue that there should be no requirement to track and
post employees and employee-hours devoted to study processing.
715. Washington IOUs also ask that the Commission not count
transmission requests submitted as part of a transmission provider's
Integrated Resource Planning (IRP) process in the calculation of
percentages of studies performed outside the 60-day window. They
contend that transmission requests associated with such studies are
often made years in advance to ensure that transmission for service of
long-term
[[Page 3072]]
load is available and can be discussed in the public domain, to allow
operational personnel to confer with one another on IRP issues in a
public forum while adhering to the Commission's standards of conduct,
and to ensure that the utility will be able to reserve transmission
capacity necessary to serve the utility's native load reliably and in a
cost-effective manner. Washington IOUs argue that there is no need for
studies associated with these requests to be performed within the 60-
day window.
716. Southern argues that the Commission should grant rehearing so
that studies for which the customer has requested or expressly agreed
to extend the 60-day study period should not be required to be included
among those studies considered to be completed late. Southern contends
that it would be arbitrary and capricious to include studies that are
``late'' due to no fault of the transmission provider (e.g., studies
delayed or extended due to customer request or action) in the metrics
calculations. Southern states that doing so could cause the
transmission provider to be automatically penalized with additional
reporting requirements and cross the threshold for which the
transmission provider must proffer excuses acceptable to the Commission
or suffer significant penalties.
Commission Determination
717. The Commission denies rehearing of the decision in Order No.
890 to require transmission providers to post standard performance
metrics regarding the processing of system impact studies and
facilities studies and, for consistently late studies, additional
performance metrics regarding the resources dedicated to processing
studies. These posting requirements are necessary to promote greater
market transparency and establish important incentives for all
transmission providers to complete transmission service requests in a
timely and transparent fashion. As the Commission explained in Order
No. 890, despite the fact that some transmission providers currently
post some information related to the processing of transmission service
requests on their OASIS, much of the public information currently
posted by transmission providers lacks transparency, accessibility, and
consistency.\285\
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\285\ See Order No. 890 at P 1308.
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718. We affirm the decision to subject all transmission providers,
including RTOs and ISOs, to the same reporting requirements. While it
may be true that data already posted by RTOs and ISOs provides much of
the information contained in the standard performance metrics, it does
not follow that posting the remaining information is unnecessary. The
independent nature of RTOs and ISOs does not justify relieving them of
this particular obligation. All transmission providers should be
subject to the same posting requirements to enhance uniformity and
transparency in processing transmission service requests and
transmission studies. Indeed, to the extent an RTO or ISO is already
posting much of this information, the incremental burden of posting the
remaining information should be minimal.
719. The Commission does not believe it is appropriate at this time
to add posting requirements regarding denials or delays in the
construction phase, as requested by Old Dominion. While construction
delays can affect transmission service start dates, the transmission
provider will be in communication with the relevant customers regarding
the status of those projects. The transmission provider is also
required to make available information regarding the status of upgrades
identified in its transmission plan, as we discuss in section III.B. We
are not persuaded that, based on the evidence before us at this time,
additional posting requirements for denials or delays in the
construction phase of transmission service requests are necessary or
appropriate. Absent particular evidence to the contrary, we believe
that other OATT provisions such as section 21.2 and the current
standard performance metrics adequately protect customers from
inappropriate delays or discrimination during construction phases.
720. We also affirm the decision to require any transmission
provider that processes more than 20 percent of non-affiliates' studies
outside of the 60-day due diligence deadlines in the pro forma OATT for
two consecutive quarters to submit a notification filing to the
Commission and post additional performance metrics. We disagree with
Washington IOUs that transmission providers should be required to post
these metrics only after Commission action on a notification filing.
Posting of these additional metrics is not required until two months
after the notification filing, giving the Commission time to consider
the extenuating circumstances that prevented the transmission provider
from processing requested studies on a timely basis. If, upon review of
such a filing, the Commission finds that delays were caused by
extenuating circumstances, the Commission will not require the
transmission provider to continue to post the additional performance
metrics. As a result, we expect transmission providers with legitimate
extenuating circumstances should not have to post any additional
metrics.
721. Similarly, we decline to exempt, as a general matter, studies
that are delayed by customer agreement or that are associated with
resource planning. The transmission provider can explain the
circumstances surrounding any particular delay in its notification
filing, which the Commission will review on a case-by-case basis. The
process adopted in Order No. 890 is sufficiently flexible to relieve
any transmission provider who completes more than 20 percent of non-
affiliates' studies outside of the 60-day due diligence deadlines for
two consecutive quarters from any additional posting requirements, or
operational penalties, if the Commission finds the delays were due to
extenuating circumstances.
722. The Commission grants rehearing to make several typographical
revisions to our rules implementing these posting requirements. In
Order No. 890, the Commission stated that short-term and long-term
requests for point-to-point service must be aggregated for purposes of
the posting requirement in order to ease the burden on transmission
providers and in recognition that many customers requesting short-term
point-to-point service are unwilling to pay for studies.\286\ The
accompanying regulations, however, stated that transmission providers
must separately calculate and post metrics for long-term and short-term
requests.\287\ Upon further consideration, we believe it appropriate to
allow, but not require, transmission providers to aggregate requests
for long-term and short-term point-to-point service for purposes of the
posting requirements. We also clarify that the posting requirements
apply to all requests for service, including requests for point-to-
point service and requests to designate new network resources or loads.
We have revised our regulations to make these requirements more clear.
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\286\ See id. at P 1309.
\287\ 18 CFR 37.6(h)(1).
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(2) Operational Penalties for Late Studies
723. The Commission determined in Order No. 890 that all
transmission providers, including RTOs and ISOs, would be subject to
operational penalties when they routinely fail to meet the 60-day due
diligence deadlines prescribed in sections 19.3, 19.4, 32.3 and 32.4 of
the OATT. Absent
[[Page 3073]]
extenuating circumstances, penalties will apply to any transmission
provider that continues to be out of compliance with these deadlines
for each of the two consecutive quarters following a notification
filing, described above, stating that the transmission provider has not
completed request studies on a timely basis. A transmission provider
will be deemed out of compliance if it completes 10 percent or more of
non-affiliates' system impact studies outside of the deadlines
prescribed in the pro forma OATT.
724. Operational penalties will be assessed on a quarterly basis,
starting with the quarter following the notification filing and
continuing until the transmission provider completes at least 90
percent of all studies within 60 days after the study agreement has
been executed. The penalty will be equal to $500 for each day the
transmission provider takes to complete any system impact study or
facilities study beyond 60 days. For any system impact study or
facilities study that is still pending at the end of the quarter and
that has been in the study queue for more than 60 days, the penalty
will equal $500 for each day the study has been in the study queue
beyond 60 days.
725. As explained above, the Commission reiterated that
transmission providers may document and describe in their notification
filing any unique complexities that particular requests introduce into
the study process and that prevent the transmission provider from
completing a study within the 60-day due diligence timeframe. On review
of a notification filing, the Commission will waive operational
penalties if a transmission provider establishes that its non-
compliance is the result of extenuating circumstances, including
factors or events that are truly beyond its control, such as delays
caused by the transmission customer. The submission of a notification
filing documenting extenuating circumstances will not, however, suspend
the obligation of a transmission provider to process at least 90
percent of the study requests within the deadlines, until such time as
the Commission issues a final determination on the notification of
extenuating circumstances.
726. The Commission declined to alter the 60-day study completion
timeframe embodied in sections 19.3, 19.4, 32.3 and 32.4 of the pro
forma OATT. The Commission concluded that this timeframe adequately
balances the need for expeditious resolution of study requests and the
need to ensure that the transmission provider can reliably accommodate
the transmission service reserved. The Commission also found that the
penalty regime adopted in Order No. 890 protects the transmission
provider in the event studies take longer to complete due to the new
planning requirements or the new requirement to consider conditional
firm options.
727. The Commission determined that revenues associated with
operational penalties for late studies should be distributed to non-
affiliated transmission customers. Transmission providers were directed
to propose a method to determine how unaffiliated transmission
customers will receive operational penalty distributions. In the event
the transmission provider has raised extenuating circumstances in its
notification filing, the Commission stated that the transmission
provider should not distribute its operational penalty while the
Commission is considering the notification filing.
Requests for Rehearing and Clarification
728. NorthWestern challenges the application of any operational
penalties for late processing of studies associated with transmission
service requests. NorthWestern contends that the most important goal of
a system impact study or facility study should be the ability to
perform an accurate study, not one that is quick, and that the
Commission cites no record evidence that penalties are necessary to
prevent unduly discriminatory completion of studies. NorthWestern
argues that all transmission providers have a financial incentive to
complete system impact studies quickly in order to maximize use of
their transmission systems. In NorthWestern's view, it is unreasonable
for the Commission to maintain a 60-day period for processing facility
studies for transmission service requests, yet allow a 90-day and 180-
day timeframe for generator interconnection facility studies which may
be equally complicated. NorthWestern argues that a study may take
longer than 60 days for a myriad of reasons and, therefore, section
19.9 of the pro forma OATT should be eliminated.
729. To the extent the Commission declines to eliminate section
19.9, NorthWestern argues that it should be waived for transmission
providers that do not have an affiliate that could benefit from any
delay. NorthWestern states that it is a transmission and distribution
utility within its Montana service territory without an active power
marketing affiliate and, as a result, the Commission's rationale for
imposing penalties is not applicable to NorthWestern and similarly-
situated transmission providers.
730. Several petitioners ask the Commission to clarify that
penalties will be assessed only if the transmission provider fails to
exercise due diligence in completing studies within 60 days. EEI argues
that the due diligence standard is sufficient to protect customers and,
therefore, the Commission's references to extenuating circumstances and
events beyond the control of the transmission provider should be
interpreted to explain some aspects of the due diligence standard,
rather than impose a new standard for completion of studies. Joined by
Progress Energy, EEI asks the Commission to modify section 19.9(iii) of
the pro forma OATT to explicitly provide that penalties will be
assessed only if the transmission provider fails to complete 90 percent
of its studies for non-affiliates within 60 days because of a lack of
due diligence or where there are no extenuating circumstances.
731. National Grid seeks similar clarification that the Commission
is not moving away from the due diligence standard in favor of an
excuse-based standard. National Grid argues that the requirement that
transmission providers provide an affirmative excuse to avoid
operational penalties for untimely studies is an unexplained departure
from precedent and inconsistent with the Commission's reference to the
due diligence standard in Order No. 890. National Grid states that the
Commission found in Order No. 2003 that financial penalties were not
appropriate for late interconnection studies and, instead, required the
transmission provider to use due diligence to perform within the
specified time frame. National Grid argues that the Commission failed
to justify use of a different, excuse-based structure with monetary
penalties in the context of studying transmission service requests.
732. National Grid, along with the Washington IOUs, opposes an
excuse-based standard, arguing that the transmission provider may not
always have a readily articulated excuse for not completing studies on
time. National Grid states that transmission providers cannot simply
hire and fire planning employees or otherwise redeploy other employees
as study queues expand and contract and that, even if they could, the
pool of qualified planning engineers is inadequate. Washington IOUs
also argue that there are numerous legitimate reasons why a
transmission provider might not process a study within the 60-day
guideline, including requests by the transmission customer to delay the
study process.
733. Several petitioners argue that the Commission should extend by
30 days or 60 days the period within which
[[Page 3074]]
studies should be completed. MidAmerican argues that strict adherence
to the 60-day target will lead to less complete analyses by limiting
the transmission provider's ability to coordinate with neighboring
systems and regional reliability organizations, which may be necessary
to understand the full effect of a proposed transaction, and forcing
the transmission provider to make assumptions regarding the impacts of
higher queued requests still in study status. E.ON U.S. similarly
argues that the length of a study is influenced by the size and type of
the line or substation upgrade required, the limited availability of
third-party contractors, and the fact that certain modeling studies can
take many weeks to prepare. MidAmerican and E.ON U.S. both argue that
internal staff limitations further impact the transmission provider's
ability to meet the 60-day target.
734. EEI, MidAmerican, and Southern argue that introduction of
conditional firm and modified planning redispatch service will
complicate the study process, may lead to an increase in study volume,
and ultimately make the 60-day deadline substantially more difficult to
meet. EEI and Southern argue that it is arbitrary and capricious for
the Commission to acknowledge in Order No. 890 that studying the
availability of these products will place increased burdens on
transmission provider without addressing the problem by granting
transmission providers more time to complete those studies.
735. MidAmerican, Progress Energy and TranServ request
clarification regarding when a system impact study is considered
complete for purposes of the 60-day due diligence deadline. Progress
Energy suggests that failure to complete a study within 60 days should
be measured from the projected start date that is included in the
applicable study agreement, rather than the date the study agreement is
executed, and that the transmission provider must clearly explain the
extenuating circumstance to the customer. MidAmerican suggests that the
milestone should be the first submission of the study report to the
transmission customer because it is customary for transmission
providers to provide a copy of the system impact study for customers to
review, which may lead to additional analysis or review of potential
issues prior to issuing a final system impact study. If provision of
the review copy of the system impact study does not satisfy the tariff
requirement, MidAmerican contends that transmission providers will
simply omit customer review and provide final studies, likely resulting
in more disputes between customers and transmission providers.
MidAmerican also argues that any delays that occur as a result of
review and acceptance of study results due to regional planning process
criteria should not subject the transmission provider to penalties.
TranServ similarly notes that certain system impact studies are subject
to regional coordination review that is out of its control. TranServ
contends that a system impact study should be deemed complete when a
study report is concurrently posted on the OASIS, provided to the
customer for review, and provided for regional coordination.
736. Some petitioners ask that the Commission exempt from potential
operational penalties certain types of studies or otherwise confirm
that delays in those circumstances will be considered extenuating
circumstances. Southern and Washington IOUs ask the Commission to make
clear that operational penalties will not apply when the transmission
provider and transmission customer expressly agree to a study schedule
providing for a study period longer than 60 days. TranServ contends
that extension of a study period to allow for clustering of multiple
requests from the same transmission customer should be deemed an
extenuating circumstance. EEI suggests that studies of the redispatch
or conditional firm options be exempted from potential penalties or, at
a minimum, that the Commission establish a one-year transition period
prior to including such studies.
737. Progress Energy asks that the Commission recognize additional
specific examples of possible extenuating circumstances, including:
prior submitted generator interconnection queue requests that impact
the same interface as transmission service queue requests; multiple
transmission service queue requests being submitted within a 60-day
period; a higher queued request that is withdrawn after it has been
accepted which can cause a restart on subsequent studies that are
underway; and a major change in transmission and generation plans of a
local or neighboring system that can cause a restart on subsequent
studies that are underway.
738. MidAmerican argues that the Commission should remove the
penalty provisions for facilities studies requiring major construction
or offer customers the option of extending the study period without
penalty to the transmission provider where a customer has a desire for
an accurate cost and schedule estimate. MidAmerican contends that the
60-day study window is inadequate to fully evaluate all the
environmental, cultural, and landowner issues to fully determine the
optimum route for a new line. Without knowing what route a line should
take, MidAmerican argues that an accurate cost estimate and schedule
cannot be prepared for the customer and, in turn, that it is
unreasonable to expect a customer to sign a service agreement based on
a highly variable cost and schedule estimate. MidAmerican also suggests
that, in cases where the transmission service requests are submitted in
association with a new generation interconnection request, coordination
with the generation interconnection queue should be explicitly allowed.
MidAmerican states that, under the Large Generator Interconnection
Procedures, the time required to determine the facilities necessary to
accommodate a generation interconnection request can exceed 250 days
from the date the interconnection request is submitted. MidAmerican
contends it is not possible to start the system impact study for the
transmission service request until after it is known what the topology
of the system will be with the new generating facility and any
associated network upgrades and, therefore, the 60-day target should
not apply.
739. E.ON U.S. requests clarification of the application of
operational penalties to its operations in particular. E.ON U.S. states
that it has delegated certain tasks, including the responsibility to
perform system impact studies, to an independent transmission
organization, i.e., Southwest Power Pool. E.ON U.S. contends that this
delegation of responsibility is consistent with or superior to the
penalties established in the pro forma OATT since it ensures that
studies will be performed in a non-discriminatory manner. In the
alternative, E.ON U.S. seeks guidance on how, or whether it may
influence the length of time it takes Southwest Power Pool to complete
system impact studies, so that they are completed within the 60-day due
diligence requirement. E.ON U.S. is concerned that it may be
responsible for penalties incurred by Southwest Power Pool for failure
to complete system impact studies for E.ON U.S. while being prohibited
from influencing the manner in which the studies are performed due to
the Commission's orders regarding Southwest Power Pool's independence.
740. TDU Systems seek clarification that imposition of an
operational penalty on a transmission provider for a late study does
not foreclose other
[[Page 3075]]
remedies to compensate for any damages arising out of a transmission
provider's lack of due diligence, such as, recovery of the incremental
cost of purchasing power from the market as well as other direct and
consequential damages, if the transmission customer can show it is
entitled to further relief. TDU Systems suggest that the Commission
explicitly recognize that a transmission provider's failure of
performance sufficient to merit the imposition of an operational
penalty also falls outside the scope of the indemnification owed by the
transmission customer to the transmission provider under OATT section
10.2.
Commission Determination
741. The Commission affirms the decision in Order No. 890 to
subject transmission providers to operational penalties when they
routinely fail to meet the 60-day due diligence deadlines prescribed in
sections 19.2, 19.4, 32.3 and 32.4 of the pro forma OATT. As the
Commission explained in Order No. 890, transmission providers must have
a meaningful stake in meeting study time frames.\288\ With the
procedural protections adopted by the Commission, the new penalties for
late study will ensure that transmission providers have an adequate
financial incentive to exercise due diligence in processing service
requests in a timely and nondiscriminatory manner.
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\288\ See Order No. 890 at P 1340.
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742. We agree with petitioners that transmission providers should
not sacrifice accuracy in order to complete studies within the 60-day
due period and that transmission providers may already have an
incentive to complete studies quickly in order to increase revenues
from transmission service. This does not mean, however, that it is
inappropriate to apply penalties in instances when transmission
providers repeatedly fail to comply with study deadlines without
justification. The notice procedures adopted in Order No. 890 give
transmission providers an opportunity to explain why studies have been
completed late. As a practical matter, then, late study penalties
should only apply to those transmission providers unable to justify
their repeated failure to meet deadlines. At the same time, the
possibility of penalties will provide appropriate incentives to ensure
that transmission providers process studies on a timely and
nondiscriminatory basis.
743. In response to concerns regarding application of the due
diligence standard, we reiterate that sections 19.3, 19.4, 32.3, and
32.4 of the pro forma OATT require transmission providers to use due
diligence to meet the 60-day study deadline. The 60-day due diligence
deadline serves as a good measure of a transmission provider's use of
due diligence since, in our experience, the vast majority of
transmission studies can be completed within that period. We recognize,
however, that certain transmission studies can present challenges or
other circumstances may justify a longer study period. The Commission
therefore adopted rules that allow transmission providers to complete
studies outside the due diligence deadlines without paying late study
penalties. In its notification filing, the transmission provider can
explain the extenuating circumstances that lead to delay and, in turn,
demonstrate that it has used due diligence in processing the relevant
studies notwithstanding its inability to meet the 60-day target.
Transmission providers should discuss any factors that they believe are
relevant, including reasonable resource limitations, the accommodation
of customer requests (including clustering), inter-regional and seams
coordination, the scope of particular studies, or fluctuations in study
volumes. On review of this information, the Commission will waive
application of late study penalties under section 19.9 of the pro forma
OATT as appropriate. We therefore do not believe any modification to
the language of section 19.9 is necessary.
744. We also reject requests to create broad categories of
extenuating circumstances that would exempt transmission providers from
late study penalties or related posting requirements. Consideration of
the particular circumstances causing a transmission provider to
repeatedly miss study deadlines is best left to a case-by-case
analysis. Again, failure to meet the 60-day due diligence deadlines
does not lead unavoidably to late study penalties, regardless of
whether the study is related to the new planning redispatch option for
long-term point-to-point service, the modified conditional firm option,
or any other service request. Granting broad exemptions for any
particular types of requests would undermine the Commission's ability
to gather information regarding the reasons for processing delays and,
in turn, ensure that those delays are justified under the
circumstances.
745. We also decline to automatically waive late study penalties
for particular types of transmission providers, such as transmission
and distribution utilities without a power marketing affiliate, as
suggested by NorthWestern, or RTOs and ISOs, as suggested by MISO. The
Commission is concerned about potential discrimination in favor of a
transmission provider's affiliated customers as well as discrimination
between different classes of unaffiliated customers. In response to
E.ON U.S., we clarify that delegating to a third party the
responsibility for conducting transmission studies does not relieve the
transmission provider of its obligation to ensure compliance with
sections 19 and 32 of the pro forma OATT. Regardless of whether the
third-party service provider is under the transmission provider's
control, the agreement governing the relationship between the service
provider and the transmission provider would establish the service
provider's responsibilities and potential liability for failing to meet
service obligations. This could include, for example, the
responsibility to submit notification filings describing any
extenuating circumstances that keep the contractor from meeting
deadlines.
746. We disagree that the 60-day due diligence period should be
extended simply because there is the possibility of penalties in the
event of repeated non-compliance. While we recognize that the timelines
we use in Order No. 890 for processing transmission service requests
may differ from those we have in place in other settings, the 60-day
deadlines have been in place for many years. We continue to believe
that 60 days is, on average, sufficient time to complete most
transmission studies. As the Commission explained in Order No. 890, and
as we reiterate above, transmission providers that are delayed due to
the addition of the conditional firm option, modification of planning
redispatch, staffing availability, or any other issues are free to
raise those issues in their notification filings.\289\ We appreciate,
and in fact intend, that the possibility of penalties will create added
incentives to complete system impact studies and facilities studies
within the 60-day due diligence deadlines. It does not follow, however,
that the deadlines themselves should change. In order for late study
penalties to apply, the transmission provider would have to be out of
compliance for at least three quarters after the reforms adopted in
Order No. 890 took effect. This gives transmission providers nine
months to adjust their operations and reallocate resources as necessary
to meet its obligation to process studies on a timely basis.
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\289\ See id. at P 1345.
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747. In response to MidAmerican and TranServ, the Commission
reiterates its current policy that transmission studies
[[Page 3076]]
will be deemed complete at the point when the transmission provider
returns a final system impact study or facilities study to the
transmission customer. Drafts of such studies, whether submitted to
regional coordinators or the transmission customer, do not satisfy this
threshold because, by definition, they are subject to revision and are
incomplete. Allowing study drafts to be considered completed for
purposes of the 60-day due diligence deadline would undermine
incentives to finalize such studies, leaving transmission customers
with little assurance that their transmission requests would be
processed in a reasonable time period. We do not mean to discourage,
however, consultation with customers or regional coordination. To the
extent such activities lead to delays, they should be explained in the
notification filing. The Commission clarifies in response to Progress
Energy that the 60-day due diligence period starts on the day the
transmission study agreement is executed unless the transmission
provider and customer agree on an alternate day for the transmission
provider to begin the study. While the transmission provider and
customer may not alter the length of the study period, they can
mutually agree as to the day on which the study begins.
748. Finally, we clarify in response to TDU Systems that payment of
a late study penalty by the transmission provider falls outside the
scope of the indemnification provided by transmission customers under
section 10.2 of the pro forma OATT. Similarly, assessment of a late
study penalty would not preclude other claims for damages to the extent
the transmission provider is liable under relevant legal principles.
(3) Recovery Through Rates
749. In Order No. 890, the Commission prohibited all jurisdictional
transmission providers from recovering penalties for late studies from
transmission customers. The Commission required non-profit transmission
providers to pay late study penalties from sources other than the
revenue they collect for sales of transmission service.
Requests for Rehearing and/or Clarification
750. Several petitioners object to the application of operational
penalties to RTOs and ISOs and request clarification of the manner in
which penalties could be recovered by RTOs and ISOs. MISO argues that
RTOs and ISOs should be exempt from the imposition of penalties because
the organizations have little or no equity cushion from which to pay
penalties and often need to obtain operational/technical information
from member transmission owners, over which they have no control, in
order to complete studies. MISO argues that, as independent entities,
RTOs and ISOs have no incentive to favor one group of customers over
another and that the Commission's unsupported reference to competing
internal priorities or staffing issues is not a reasoned substitute for
the undue discrimination rationale on which the Commission's reforms
are based. MISO argues that the distinction between an RTO and a single
system transmission provider is particularly acute for MISO, PJM, and
Southwest Power Pool, which have been required by the Commission to
execute seams operating agreements that require the sharing of planning
information.
751. MISO objects to the potential use of funds set aside for
salaries or bonuses to pay penalties, suggesting that budget cuts are
not an appropriate remedy for staffing issues. MISO contends that RTOs
and ISOs should be allowed to recover penalties in rates. MISO states
that reliability rules permit RTOs and ISOs to recover their ERO
penalties in rates and the same should be allowed for operational
penalties. MISO acknowledges that the Commission allowed transmission
providers an opportunity to avoid operational penalties by showing that
failure to meet the compliance threshold is due to extenuating
circumstances, but objects to that process as burdensome. MISO argues
that it is unclear what circumstances would be considered extenuating,
suggesting that some customers request service well in advance because
they are aware of possible delays in performing necessary studies. To
the extent the Commission retains financial penalties for RTOs and
ISOs, it suggests that delays resulting in no harm to the customer
should not be included in the 10 percent threshold.
752. EEI, National Grid, and ATCLLC argue that the Commission first
should consider non-monetary penalties for RTOs and ISOs, such as
increased oversight, before assessing any monetary penalties. ATCLLC
and National Grid contend that using a non-monetary enforcement policy
for violations of the OATT would more closely mirror the policy adopted
by the Commission with respect to enforcement of reliability standards,
as reflected in NERC Sanction Guidelines. National Grid suggests that
the Commission not take the next step of imposing monetary penalties
(whether operational or civil penalties) on RTOs or ISOs absent
extraordinary reasons, such as repeated or willful violations.
753. If monetary penalties are assessed on an RTO or ISO, National
Grid argues that the non-profit status of RTOs and ISOs justifies
allowing those entities to recover the cost of penalties through rates,
provided those costs are allocated to all market participants fairly.
ATCLLC and Duke, however, oppose recovery of any operational or civil
penalties in the rates of an RTO or ISO. ATCLLC argues that allowing
RTOs and ISOs to include penalties in their cost of rendering
transmission or market services would defeat the purpose of the
penalty. In its view, the pass-through of penalty costs would be
tantamount to imposing the financial consequences of an action on
parties that did not commit the violation, that may not have any
control over the action causing the violation, and who may have been
negatively impacted by the violation. Duke asks the Commission to
clarify that the other sources of money from which RTOs and ISOs must
pay operational or civil penalties do not include any rates collected
from customers, including administrative charges, energy charges, or
charges for transmission-related services.
Commission Determination
754. The Commission affirms the decision in Order No. 890 to
prohibit transmission providers from automatically passing through to
transmission customers the cost of late study penalties. The 60-day due
diligence standard is in place to protect customers and it would
therefore be inappropriate to automatically recover from those
customers penalties assessed for non-compliance. We are mindful of the
unique operating and budgetary concerns of independent transmission
providers with respect to their ability to pay late study penalties and
will keep those concerns in mind when reviewing these transmission
providers' notification filings. However, as we explain in section
III.C.4.c, it would not be appropriate to exempt, on a generic basis,
any particular class of transmission providers from the requirement to
pay operational penalties.
755. The Commission acknowledged in Order No. 890 that the
independence of RTOs and ISOs removes incentives to favor one group of
customers over another. Notwithstanding this independence, competing
internal policies or staffing issues could lead to particular types of
customers being treated differently during the study process. The
potential application of penalties for consistently late studies
[[Page 3077]]
ensure that the proper incentives are in place to process request
studies in a timely and non-discriminatory manner for every customer.
The limited ability of an independent transmission provider to absorb
late study penalties is more appropriately considered when determining
the penalty, if any, that will apply to an RTO or ISO on review of its
notification filing, which would not be possible if a blanket exemption
were granted.\290\
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\290\ We clarify that, as part of this analysis, we will
consider whether the use of non-monetary penalties would be
appropriate in the circumstances.
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756. As explained in section III.C.4.c, we decline to state here
the particular sources of funds from which an RTO or ISO should pay any
late study penalties ultimately imposed. We do clarify, however, the
Commission's statement in Order No. 890 that an RTO or ISO may not use
revenues from sales of transmission service to pay late study
penalties.\291\ It may be the case that an RTO's or ISO's only source
of funds is from rates collected from jurisdictional transmission
customers. The Commission's intent in restricting transmission
providers, including RTOs and ISOs, from automatically passing on to
customers the costs of late study penalties was to prohibit those
transmission providers from designing their rates to accommodate a pass
through of the penalties, i.e., effectively including penalties in its
cost of service. A transmission provider is permitted to use revenues
previously collected under Commission-approved rates to pay late study
penalties by reallocating funds as necessary to distribute late study
penalty amounts.
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\291\ Id. at P 1357.
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757. We clarify in response to MISO that, if the RTO or ISO is
unable to identify any appropriate funds from which to pay a late study
penalty, the Commission will consider case-specific cost-recover
proposals under FPA section 205. As explained above, such proposals
should not include mechanisms to automatically pass through to
customers any penalties approved to the RTO or ISO.
(4) Clustering Transmission Service Request Studies
758. Although the Commission did not impose, in Order No. 890, a
requirement for transmission providers to study transmission requests
in a cluster, the Commission did encourage transmission providers to
cluster request studies when reasonable. In particular, the Commission
directed transmission providers to consider clustering studies if
requested to do so by a group of transmission customers and the
transmission provider can reasonably accommodate the request. To that
end, the Commission required each transmission provider to include
tariff language in its compliance filing that describes how it will
process a request to cluster studies and how it will structure the
transmission customers' obligations when they have joined a cluster.
Requests for Rehearing and/or Clarification
759. TranServ requests clarification that, if the transmission
provider receives a large number of study requests from the same
customer within a short time period with no other customer requests
commingled, it may be prudent to combine these studies into a clustered
study group to reduce costs and study queue volumes, even recognizing
that such a practice would result in an extended study period.
Commission Determination
760. In Order No. 890, the Commission required transmission
providers to study transmission requests in a cluster if the customers
involved request the cluster and the transmission provider can
reasonably accept the request. The Commission did not preclude
transmission providers from clustering additional request studies if
they believe it reasonable to do so. Studying transmission service
requests in a cluster in some cases can create synergistic benefits,
simplify complex, interrelated transmission requests, and help
transmission providers reduce study queue backlogs. To the extent a
transmission provider wishes to adopt additional procedures governing
the clustering of requested studies, it may propose such procedures in
a filing under section 205 of the FPA demonstrating that clustering
will be implemented in a timely and non-discriminatory fashion.
761. Although we agree that in certain circumstances the time
required to process a clustered study group may exceed the time
required to study a single transmission request, we do not agree that
this should be always be the case. As the Commission explains above, we
will not exempt broad categories of extenuating circumstances, such as
the clustering of request studies, from the 60-day due diligence
deadline.
(5) Standardization of Business Practices for Study Queue Processing
762. The Commission also required transmission providers working
through NAESB to develop business practice standards to better
coordinate transmission requests across multiple transmission systems.
In order to provide guidance to NAESB, the Commission articulated the
principles that should govern processing across multiple systems. The
Commission further required transmission providers working through
NAESB to develop business practice standards to allow a transmission
customer to rebid a counteroffer of partial service so the transmission
customer can take the same quantity of service for linked transmission
service requests across multiple systems. The Commission explained that
the transmission customer should not be required to take the same
quantity of service across consecutive transmission service requests
and, instead, it should simply have the option to do so.
Requests for Rehearing and Clarification
763. TDU Systems argue that the Commission erred by failing either
to mandate coordination among transmission providers or to provide the
oversight necessary to ensure that NAESB effectively addresses the
standards and practices for coordination. TDU Systems contend that
transmission customers have experienced denials of service because of
differing response times to transmission service requests spanning
multiple transmission systems and that a lack of coordination among
transmission providers reduces accountability for potentially anti-
competitive denials of service. To the extent the Commission relies on
business practices by NAESB, TDU Systems contend that the Commission
must provide clear deadlines for NAESB to complete the development
process for these business practices. TDU Systems argue that failure to
establish deadlines in this context, while establishing clear deadlines
for the development of ATC-related standards, is arbitrary and
capricious.
764. TAPS asks the Commission to articulate more fully the
coordination necessary between transmission providers when a customer's
request entails use of multiple systems. TAPS notes that the Commission
refers in Order No. 890 to coordination of studies across multiple
systems, but that coordination may be unnecessary if one of the
affected transmission providers conclude that no system impact study is
required. TAPS contends there is nonetheless a need to coordinate such
requests so that the customer is not required to confirm service on the
no-study system before knowing whether service is available on the
other piece of the transmission path.
[[Page 3078]]
765. TAPS also requests confirmation that, in the event only one of
the transmission providers considering a multi-system request
determines that a facilities study is necessary, the transmission
provider whose system impact study did not lead to a facilities study
must await the completion of the other transmission provider's
facilities study prior to requiring the customer to commit to the
service or lose its queue position. Similarly, TAPS argues that, if
both transmission providers find a need to undertake facilities
studies, the customer should not be subject to different deadlines for
entering into those facilities studies or committing to service after
all of the facilities studies are completed.
Commission Determination
766. The Commission affirms the decision in Order No. 890 to rely
on the NAESB process to develop business practices to govern the
processing of transmission requests across multiple transmission
systems. We decline to dictate at this time, beyond those principles
outlined in Order No. 890, the particular practices that must be
implemented. It is more appropriate to allow transmission providers
working through NAESB, in the first instance, to consider how best to
ensure coordination across multiple systems. It is also appropriate to
give NAESB an open timeframe to develop these standards since they must
be broad enough to account for the complexities of coordinating multi-
system transmission service requests.\292\
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\292\ NAESB has indicated that business practices governing the
coordination of service requests across multiple transmission
systems are in development. The Commission requests NAESB to keep us
informed regarding the status of developing these and other business
practices.
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767. The appropriate forum for TDU Systems and TAPS to raise
substantive concerns regarding the coordination required for multi-
system requests is therefore the NAESB process. If concerns remain at
the conclusion of this process, transmission providers and customers
alike can bring them to the Commission's attention on review of the
NAESB business practices.
(6) Additional Processing Proposals
768. In response to commenter requests, the Commission revised
section 17.7 of the pro forma OATT so that the transmission provider is
able to terminate a request for transmission service if a customer that
is extending the commencement of service does not pay the required
annual reservation fee within 15 days of notifying the transmission
provider that it would like to extend the commencement of service. The
Commission denied a request to require transmission providers to accept
or deny in all cases non-firm and short-term firm point-to-point
transmission service requests solely based on posted ATC, explaining
that transmission providers should not be discouraged from making
service available when posted ATC is not accurate.
Requests for Rehearing and/or Clarification
769. Southern argues that the Commission should revise the amended
provisions of section 17.7 of the pro forma OATT to ensure that
transmission customers cannot escape their contractual commitments by
simply failing to timely make an extension of service payment. Southern
contends that the language of section 17.7 of the pro forma OATT makes
the termination of a customer's reservation mandatory, while the
Commission's discussion of that language in Order No. 890 indicated an
intention for such termination to be permissive.\293\ Southern contends
that mandating termination in the event of non-payment would allow
customers to easily escape contractual commitments even where the
transmission provider has reserved the underlying transmission capacity
for that customer. Southern requests that section 17.7 be revised to
state: ``If the Transmission Customer does not pay this non-refundable
reservation fee within 15 days of notifying the Transmission Provider
it intends to extend the commencement of service, then the Transmission
Provider may deem the Transmission Customer in breach and may terminate
the Transmission Customer's Service Agreement.''
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\293\ Citing Order No. 890 at P 1390.
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770. Southern also requests clarification that transmission
providers are allowed to study and condition a request for extension of
service for long-term agreements having a term of less than five years.
Southern states that, under the prior rollover policy, it was able to
condition the continuation of service beyond the contract term so long
as the condition was stated in the service agreement. Once the rollover
reforms become effective and the rollover right extends only to
contracts of five years or longer, Southern contends that it will no
longer evaluate service availability beyond the requested term of
service during the system impact and facility studies. Where such
service is not available, Southern contends it would not be possible to
grant an extension of the commencement date. Southern therefore asks
the Commission to allow transmission providers to study, and possibly
limit, all requests for extensions of commencement of service for long-
term agreements having a term of less than five years. If the
Commission declines to grant this request generally, Southern argues
that such studies at a minimum should be allowed for extensions of
commencement of service for customers having agreements for planning
redispatch or conditional firm service. Southern contends there is
increased need for continued study regarding the availability of those
products, as the Commission recognized by allowing a two-year
reassessment period for the products.
771. Powerex repeats its request to require transmission providers
to respond to short-term transaction requests based on the ATC quantity
posted at the time the request is granted. Powerex contends that
allowing transmission providers to grant or deny service inconsistent
with posted ATC encourages transmission customers to always have
requests pending in the queue and may lead to customers ultimately
viewing the transmission provider's actions as discriminatory. Powerex
argues that the Commission cited no evidence that its proposal would be
unworkable, operationally problematic, or inefficient, nor explained
how its ruling is consistent with the emphasis placed on accurate,
timely and consistent ATC postings elsewhere in Order No. 890.
772. Powerex also repeats a request to modify the language of
sections 17.1 and 17.5 of the pro forma OATT to give transmission
providers the flexibility to grant short-term transmission service
requirements without performing a system impact study.\294\ Powerex
argues that requiring transmission providers to perform system impact
studies to evaluate short-term service requests imposes deadlines that
are often unworkable. Powerex also contends that a refusal to modify
sections 17.1 and 17.5 would be at odds with the Commission's decision
in Entergy Services, Inc.,\295\ in which the Commission allowed Entergy
to evaluate short-term requests without performing a system impact
study. Powerex argues that the ATC-related reforms adopted in Order No.
890 will
[[Page 3079]]
ensure that this flexibility will not impair system reliability.
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\294\ Powerex initially raised this issue in the context of the
definition of a system impact study and, thus, the Commission
addressed the argument in section V.D.10 of Order No. 890.
\295\ Entergy Services, Inc., 101 FERC ] 61,169 (2002).
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Commission Determination
773. The Commission grants rehearing to revise section 17.7 of the
pro forma OATT in order to define more equitably the rights and
obligations of customers failing to make timely payment of deposits in
order to extend the commencement of service. Upon further
consideration, we conclude that it would be inappropriate for a
transmission customer to lose its underlying transmission service
agreement simply because it failed to comply with the requirements of
extending the service commencement date. We believe that it is more
equitable to require those transmission customers who seek an extension
of service, but fail to pay the required deposit in a timely fashion,
to lose only their option to extend their transmission service start
date and not the underlying transmission service agreement.
774. We therefore decline to adopt the language proposed by
Southern, since that could still result in the transmission customer
losing its entire transmission service agreement based on a
technicality. The revised language of section 17.7 will more
appropriately resolve Southern's stated concern about a transmission
customer's use of the 15-day deadline in section 17.7 of the pro forma
OATT to escape its underlying transmission service agreement. If a
transmission customer fails to make the appropriate payment to extend
service, that customer remains obligated to take service under the
original terms and conditions of the underlying transmission service
agreement.
775. We agree with Southern, however, that transmission providers
should have the opportunity to consider the ability to provide service
in the event of an extension for commencement of service. Under prior
rollover policies, transmission providers considered whether long-term
service would continue to be available beyond the original requested
term during their initial consideration of the request for service,
since transmission providers were required to identify in the initial
service agreement any restrictions on the customer's rollover rights.
Once the rollover reforms adopted in Order No. 890 become effective,
transmission providers will undertake that analysis only for contracts
with a term of five years or more. Transmission providers should
continue to have the opportunity to consider the availability of
extended service for contracts with terms of less than five years once
the rollover reforms become effective. We therefore revise section 17.7
of the pro forma OATT to make clear that extensions of service are
subject to availability. For contracts of five years or longer, we
expect that identification of any restrictions on rollover rights in
the initial service agreement will continue to serve as corresponding
restrictions on the ability of the customer to extend the commencement
of service.
776. We affirm the decision in Order No. 890 not to require
transmission providers to grant certain short-term transmission service
requests based only on posted ATC values. Transmission providers are in
the best position to determine how much capacity exists on their system
in real-time and, therefore, it would not be appropriate for the
Commission to categorically preclude transmission providers from making
such short-term allocations on a case-by-case basis. We do not wish to
preclude transmission providers from making service available at times
when posted ATC is not accurate. The transmission provider nevertheless
must act on a non-discriminatory basis when using its discretion to
grant service when posted ATC is insufficient. As the Commission stated
in Order No. 890, the transmission provider must log such instances as
an act of discretion and post the log so that the Commission and
customers may monitor the transmission provider's actions.\296\
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\296\ See Order No. 890 at P 1389 (citing 18 CFR 37.6(g)(4)).
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777. We clarify in response to Powerex that sections 17.1 and 17.5
of the pro forma OATT do not require transmission providers to
undertake system impact studies for all requests for short-term
transmission service. System impact studies are only required if it is
necessary to evaluate the impact of the request prior to granting
service. While we would expect a transmission provider to use its
knowledge of its system, including prior studies and system
assessments, to grant short-term requests when possible, the
transmission provider must in every instance consider whether a system
impact study is in fact required to evaluate the request for
transmission service, as the very precedent cited by Powerex
contemplates.\297\ We recognize that on occasion a study period could
exceed the length of service requested by a transmission customer and
thereby render moot the transmission service request. As the Commission
explained in Order No. 890, however, implementing a generic rule to
eliminate or shorten the period for performing system impacts could
jeopardize system reliability.\298\ We therefore decline to adopt
Powerex's suggested revisions to sections 17.1 and 17.5.
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\297\ See Entergy Services, Inc., 101 FERC ] 61,169 at P 9-10
(stating that Entergy would have information to evaluate requests
for short-term service without a system impact study ``in most
instances'' and should not ``unnecessarily rel[y]'' on system impact
studies'').
\298\ See Order No. 890 at P 1707.
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b. Reservation Priority
(1) Priority for Pre-Confirmed Requests
778. The Commission determined in Order No. 890 that longer
duration service requests will continue to have priority over shorter
duration service requests, with pre-confirmation serving as a tie-
breaker for requests of equal duration. The Commission further provided
that pre-confirmed, non-firm point-to-point transmission service
requests and short-term, firm point-to-point transmission service
requests would have priority over non-confirmed, non-firm and short-
term requests, respectively, of equal duration. Pre-confirmed requests
for transmission service will not preempt an equal duration request
that has already been confirmed.
779. The Commission also clarified its policies regarding the
treatment of pre-confirmed requests in order to address concerns
regarding operational difficulties caused by giving priority to such
requests. First, the Commission prohibited transmission customers from
withdrawing pre-confirmed, non-firm and short-term firm point-to-point
transmission service requests prior to when the transmission customer
is offered service or a system impact study. Transmission providers
shall invalidate, however, a pre-confirmed request at the request of
the transmission customer in the very near term following submittal of
the request, in the event the transmission customer makes an
inadvertent error in submitting its request. Second, the Commission
explained that a customer is not bound to take service when the
transmission provider counteroffers the customer's initial request,
although it is obligated to take service in the event the transmission
provider offers the service requested.
Requests for Rehearing and Clarification
780. TranServ objects to the retention of priority for longer-term
service, regardless of pre-confirmation status. TranServ maintains that
the advantages of longer-term services in the form of redirect
opportunities and secondary market sales are sufficient incentives in
and of themselves and that the ability to preempt shorter term service
is
[[Page 3080]]
unnecessary to promote longer term sales. TranServ acknowledges that
the preemption and matching provisions have been in the pro forma OATT
since Order No. 888, but questions the extent to which they have been
fully implemented into the business practices of all transmission
providers. TranServ argues that transmission customers would prefer to
have transaction certainty once they have confirmed service instead of
remaining in an uncertain, conditional state up until the relevant
scheduling deadline. TranServ also suggests that retention of the
preemption policy will impede development of the secondary market for
transmission capacity, questioning whether customers would see any
value in entering into a secondary market purchase that is subject to
preemption or understand their rights and obligations, and those of the
assignee, in the event preemption occurs.
781. If the Commission retains the priority for longer term
service, TranServ requests clarification of how preemption is to be
implemented in certain circumstances. TranServ questions whether a
reservation for consecutive terms of service is considered
``unconditional'' in its entirety when the first increment of service
becomes unconditional. For a reservation for three consecutive days of
daily service, TranServ asks whether that entire reservation (three
days) is considered unconditional one day prior to the start of
service, or whether only the first day of that three-day reservation
becomes unconditional and not subject to preemption.
782. Ameren maintains that the Commission should include priority
for pre-confirmed long-term firm requests to ensure that long-term uses
are allocated to those customers that have the greatest demand. Ameren
contends that excluding long-term firm requests from consideration as
pre-confirmed requests may distort the transmission service queue and
affect existing long-term firm uses of the grid, such as agreements
eligible for rollover rights, by triggering the requirement to match a
competing request that has not been confirmed. Ameren requests that the
Commission require priority for pre-confirmed requests of all durations
of firm service or, at a minimum, require that any request that
competes with a long-term firm transmission service agreement eligible
for rollover must be pre-confirmed.
783. E.ON U.S. argues that it is not clear what happens to a pre-
confirmed request if the transmission provider only can provide the
requested service if additional facilities are constructed. E.ON U.S.
requests clarification whether an offer to provide service if
additional facilities are constructed is a counteroffer that allows the
customer submitting a pre-confirmed request to decline service.
784. Tenaska requests additional flexibility regarding the
withdrawal of pre-confirmed requests. Tenaska suggests that the
Commission establish a defined period, up to the point prior to the
processing of the request by the transmission provider, during which
pre-confirmed, non-firm and short-term firm point-to-point transmission
service requests may be withdrawn for any reason and without penalty.
Tenaska argues this flexibility is necessary to ensure that point-to-
point customers are not competitively disadvantaged vis-a-vis network
service customers when obtaining ATC, since network customers pay no
additional cost for transmission they cannot use.
785. Southern suggests that the Commission allow transmission
providers working through NAESB sufficient time to develop procedures
for processing competing pre-confirmed requests, including how a
request whose evaluation is in progress should or should not be
impacted by a new pre-confirmed request received prior to such
evaluation being completed.
Commission Determination
786. The Commission affirms the decision in Order No. 890 to give
priority based on pre-confirmed status only to short-term firm and
long-term non-firm requests for service. As the Commission explained in
Order No. 890, the Commission was mindful that the pre-confirmation
process could disrupt the transmission study process, undermine longer-
term uses of the transmission system, or disadvantage transmission
customers that are not in a position to pre-confirm their requests.
Restricting the scope of transmission service requests receiving
priority for pre-confirmation status to short-term firm and long-term
non-firm service requests is necessary in order to minimize disruptions
with existing study procedures and power procurement practices in place
for long-term firm service requests. We believe this appropriately
balances the need to promote long-term transmission rights against the
need for increased certainty for customers seeking shorter-term firm
and non-firm service.\299\ Similarly, we decline to alter the
Commission's long-standing policy of giving longer duration requests
for service priority over shorter duration requests. To do so would
undermine the Commission's goal of encouraging longer term uses of the
transmission system.
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\299\ As we explain in section III.D.2.c, a customer exercising
a rollover right is only required to match a bona fide competing
commitment to take service, evidenced for example by a pre-confirmed
transmission request or the execution of a contingent service
contract.
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787. We clarify in response to E.ON U.S. that, in the event an
offer for service on a pre-confirmed request can only be accommodated
by additions to the transmission provider's transmission system, the
transmission customer may: (1) Take a shorter term of service, if
available; (2) agree to undertake any upgrades that may be necessary to
accommodated the transmission requests; or (3) decline service. The
Commission rejects Tenaska's proposal to adopt a deadline prior to
which a transmission customer may withdraw a pre-confirmed transmission
service request. Providing an opportunity to pre-confirm applications
is intended to reduce overloading of transmission study queues and
minimize the amount of transmission requests later withdrawn from the
study queue, increasing the efficiency of processing transmission
service requests. Allowing transmission customers to withdraw pre-
confirmed transmission service requests without reason or penalty as
suggested by Tenaska would undermine the very reason pre-confirmation
status has been given a priority.
788. We decline Southern's request to extend the effectiveness of
the reforms regarding pre-confirmation priority pending development of
related business practices by NAESB. We believe that Order No. 890
provides sufficient guidance for transmission providers to implement
this priority in advance of any standardization efforts that may be
undertaken through the NAESB process.
789. With respect to TranServ's question regarding application of
the right of first refusal for eligible customers with requests for
service over multiple days, the Commission clarifies that a competing
request must exceed the total term of service in order to trigger the
right of first refusal. Thus, in order for a competing request of equal
price to preempt a reservation for three conservative days of daily
service, that request must be for four consecutive days or longer and
must be received at least one day before the first day of the original
customer's three-day term of service.
790. Upon review of tariff provisions governing pre-confirmation of
transmission service requests, the Commission has determined that the
language adopted in Order No. 890 did
[[Page 3081]]
not fully capture the Commission's intent of allowing all eligible
customers the opportunity to pre-confirm short-term firm and non-firm
reservations. As currently written, the language of sections 1.39, 17.2
and 18.2 of the pro forma OATT make pre-confirmation available only to
those that are already transmission customers, rather than all eligible
customers. The Commission has revised those sections of the pro forma
OATT to more accurately reflect our intent that pre-confirmation
service should be available to all eligible customers seeking short-
term firm and non-firm transmission services.
(2) Price as a Tie-Breaker
791. In Order No. 890, the Commission added price as a tie-breaker
in determining reservation queue priority when the transmission
provider is willing to discount transmission service, so that price
will serve as a tie breaker after pre-confirmation status. The
Commission clarified that, in the event a later queued short-term
request for transmission service preempts a conditionally confirmed
short-term request for transmission service based on price, the
conditionally confirmed request has a right to match the price offer of
the later queued request.
Requests for Rehearing and Clarification
792. E.ON U.S. requests clarification that the use of price as a
tie-breaker means that a customer that is receiving service and that is
not otherwise subject to a discount will receive a reservation priority
over one who receives a discount. E.ON U.S. states that transmission
service is not provided at market-based rates and, thus, using price as
a tie-breaker cannot mean that a customer offering a market-based price
is to be rewarded with reservation priority.
Commission Determination
793. We agree with E.ON U.S. that use of price as a tie-breaker
does not mean that a customer is offering to be charged a market-based
rate by the transmission provider. Under section 13.2 of the pro forma
OATT, price serves as a tie-breaker among competing service requests of
equal duration only when the transmission provider has offered a
discount or a ``below ceiling rate'' on transmission service.
Transmission providers may not charge rates above those stated in their
OATT for primary transmission capacity.\300\
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\300\ The Commission addresses the reassignment of transmission
service in the secondary market in section III.C.3.
---------------------------------------------------------------------------
(3) Five-Minute Window for Requests
794. The Commission determined in Order No. 890 that the first-
come, first-served policy for transmission service under the pro forma
OATT should remain largely intact. The Commission allowed, but did not
generally require, transmission providers to propose a window within
which all transmission service requests the transmission provider
receives will be deemed to have been submitted simultaneously. Only
transmission providers that have adopted a ``no earlier than'' time for
submitting transmission service requests were required to treat
transmission service requests received within a specified period of
time as having been received simultaneously. The Commission stated that
the submittal window for these transmission providers must be open for
at least five minutes unless the transmission provider can present a
compelling rationale to justify a shorter submittal window. The
Commission required these and any other transmission providers deeming
requests submitted within a specified period as having been submitted
simultaneously to propose a method for allocating transmission capacity
if requests submitted within the same time period exceed available
capacity.
Requests for Rehearing and Clarification
795. Powerex and Southern protest the Commission's departure from
the long-standing first-come, first-served priority scheme. Powerex
contends that, of the commenters supporting a simultaneous-priority
window, none presented evidence that they were less sophisticated, had
fewer financial resources, or had encountered prohibitively high
software and other costs associated with operating an efficient
transmission reservation desk. Powerex argues that the Commission
mischaracterized support for the window proposal, stating that half of
the critics of the proposed window provide and/or use transmission
predominantly within the Western Interconnection.
796. Powerex, Southern, and Tenaska suggest that use of a
simultaneous priority window will lead to implementation and
operational problems, requiring transmission providers to allocate
transmission capacity among multiple requesting customers, resulting in
customers potentially receiving unusable blocks of capacity. Powerex
contends that the Commission has relied on first-come, first-served
priority in other contexts based on a similar concern that pro rata
allocation of scarce capacity may result in blocks too small for the
customer to use.\301\ If the Commission does not grant rehearing on
this issue, Southern asks the Commission, at a minimum, to clarify that
NAESB will be permitted to address and resolve in a uniform fashion the
numerous operational issues associated with treating all requests
received within a certain timeframe as having been received
simultaneously.
---------------------------------------------------------------------------
\301\ Citing Trailblazer Pipeline Co., 108 FERC ] 61,049 (2004).
---------------------------------------------------------------------------
797. Powerex further argues that, with a pro rata window approach,
transmission customers with multiple affiliates will be able to secure
more usable blocks of capacity by pooling their requests through
reassignment, while single-entity customers will confront numerous
transaction obstacles to obtain a similar result. Powerex again points
to precedent in the gas context, arguing that the Commission recognized
similar concerns to support a first-come, first-served approach for
reserving pipeline capacity.\302\ Powerex argues that the Commission
failed to address these concerns. Finally, Powerex objects to the
Commission's characterization of the first-come, first-served priority
structure as arbitrary, arguing that a specified window is equally
arbitrary since it separates by a millisecond those that fall within
the simultaneous window and those that fall outside.
---------------------------------------------------------------------------
\302\ Citing id.
---------------------------------------------------------------------------
798. If the Commission declines to grant rehearing of the use of a
simultaneous priority window, Powerex requests clarification regarding
its implementation. First, Powerex contends that a simultaneous window
must commence at the start of the ``no later than'' hour and conclude
five minutes later, and not be a ``rolling window'' that groups
together service requests submitted within five minutes of each other.
Second, Powerex requests clarification that the simultaneous priority
window would not apply to hourly transmission service, to the extent it
is offered by the transmission provider, arguing that there is
insufficient time for customers to monitor the multitude of various
transmission providers' windows for hourly requests and that potential
pro rata allocations of hourly service would have little value to
customers.
799. Tenaska similarly argues that the Commission must provide
clear, uniform guidance as to what methods will, and will not, be
acceptable for allocating transmission capacity when there is
insufficient capacity to satisfy requests deemed to have been submitted
simultaneously, as well as further guidance regarding the window period
[[Page 3082]]
that a transmission provider may designate. Tenaska contends that the
Commission has given transmission providers too much discretion by
allowing them to propose a method for allocating transmission capacity
if sufficient capacity is not available to meet all requests submitted
within the specified time period. Tenaska argues that such discretion
is a potential breeding ground for undue discrimination and, therefore,
that the Commission should provide additional guidance to ensure that
the methods for allocating transmission capacity minimize the
opportunity for gaming.
800. Ameren asks the Commission to clarify that any proposal to
voluntarily adopt an equivalent priority standard must be clearly
defined and supported. Ameren suggests that an applicant submitting a
proposal for a five-minute equivalent priority standard must make clear
whether it is proposing to use a rolling five-minute window or whether
it will use a series of discrete five-minute windows. Ameren contends
the applicant also should be required to clearly explain what sort of
tie-breaking mechanisms it will use.
801. EEI asks the Commission to clarify the requirement to adopt a
submittal window is not triggered by a ``no earlier than'' time for
requests for non-firm service. EEI notes that section 18.3 of the pro
forma OATT requires all transmission providers to impose limits on how
early a request for non-firm service may be submitted. EEI therefore
argues that the requirement to adopt a submittal window should apply
only to transmission providers that have established a ``no earlier
than'' time for requests for firm point-to-point or network service.
Commission Determination
802. The Commission denies rehearing of the Commission's decision
in Order No. 890 to require transmission providers that have adopted a
``no earlier than'' time for submitting requests for firm transmission
service to treat all requests received within a specified period of
time as having been received simultaneously.\303\ We agree with
petitioners that the Commission's long-standing first-come, first-
served policy is a simple and efficient way for transmission providers
to allocate firm transmission capacity among competing service
requests. For this reason, Order No. 890 generally grants transmission
providers the discretion to determine which transmission services, if
any, will be subject to a submittal window. The Commission recognized
only one exception to this rule: when the transmission provider has
established dates before which requests for firm transmission service
will not be accepted.
---------------------------------------------------------------------------
\303\ We agree with EEI that the requirement to establish a
submittal window applies to those transmission providers that have
adopted a ``no earlier than'' time for the submission of firm point-
to-point or network service. The pro forma OATT contains a ``no
earlier than'' time that applies to requests for non-firm point-to-
point service, which we do not intend to trigger the requirement to
establish a submittal window.
---------------------------------------------------------------------------
803. As the Commission explained in Order No. 890, the first-come,
first-served policy can disadvantage certain transmission customers
when a ``no earlier than'' restriction is in place.\304\ Such a
restriction forces transmission customers competing for transmission
capacity to precisely time their requests for service such that they
are received after the ``no earlier than'' time, yet before other
customers. This has the potential of disadvantaging transmission
customers that are less sophisticated and have fewer financial
resources. The Commission stated in Order No. 890 that, when
considering requests for firm transmission service received after the
``no earlier than'' time has expired, there is no meaningful difference
between those received seconds ahead of another because one customer's
computer is slower than another and no petitioner argues otherwise on
rehearing.\305\
---------------------------------------------------------------------------
\304\ See Order No. 890 at P 1419.
\305\ Id.
---------------------------------------------------------------------------
804. We clarify in response to Ameren and Powerex that each
transmission provider has discretion to determine how its submittal
window will be implemented, including the point at which the window
goes into effect. Although the Commission agrees with Powerex, in
principle, that it would be logical for submittal windows to begin on
the first minute of the ``no earlier than'' time, we will not
categorically dismiss alternatives to this arrangement since these
procedures are best reviewed on a case-by-case basis. Similarly, any
transmission provider that has implemented hourly firm point-to-point
service should address how the submittal window would be implemented
for that service, including any limitations on the use of a submittal
window for that product. It is more appropriate for the Commission to
consider customer concerns regarding use of a submittal window for
hourly firm transmission service in the context of the transmission
provider's particular proposal.
805. The Commission recognizes that developing methods to allocate
capacity among requests received during a submittal window may require
detailed procedures, particularly when transmission requests received
simultaneously exceed available capacity. As the Commission explained
in Order No. 890, however, we believe that each transmission provider
is in the best position to develop allocation procedures that are
suitable for its system. This does not preclude transmission providers
from working through NAESB to develop standardized practices, as
suggested by Southern. For example, as we pointed out in Order No. 890,
allocation methods such as that used by PJM to allocate monthly firm
point-to-point transmission service could provide useful guidance in
developing general allocation procedures.\306\
---------------------------------------------------------------------------
\306\ See id. at P 1422.
---------------------------------------------------------------------------
806. The Commission disagrees with Tenaska that allowing
transmission providers to develop a methodology to allocate
insufficient capacity will lead to undue discrimination. As Ameren
suggests, each transmission provider must clearly define and support
its allocation methodology in its tariff and, thus, customers can raise
any concerns regarding the potential for discrimination during the
Commission's review of the relevant tariff language. Once the tariff
language is in place, transmission customers can, and should, bring to
the Commission's attention any failure by the transmission provider to
follow its tariff. While the Commission could remove transmission
provider discretion in this area by adopting a single, one-size-fits-
all approach, such as a mandatory pro rata distribution methodology,
this approach may not produce the best result in all cases. As the very
precedent cited by petitioners acknowledges, every allocation
methodology has advantages and disadvantages.\307\ We reiterate our
belief that transmission providers are in the best position to
determine which allocation mechanism works best for their systems.
---------------------------------------------------------------------------
\307\ See Trailblazer Pipeline Co., 108 FERC ] 61,049 at P 41.
The Commission in that case accepted a pipeline's proposal not to
use pro rata allocations in the event tie breaking was necessary out
of a concern that resulting amounts of capacity would be too small
to be of real use to a shipper. Shippers, however, had argued for
use of pro rata allocations to increase the number of parties that
could serve a market. Based on the circumstances of that case, the
Commission accepted the proposal to use a first-in-time tiebreaking
methodology. It does not follow, however, that use of a pro rata
allocation would be inappropriate in all circumstances.
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(4) Right of First Refusal and Preemption
807. The Commission declined in Order No. 890 to otherwise change
the ``first come, first served'' nature of the
[[Continued on page 3083]]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]
[[pp. 3083-3132]] Preventing Undue Discrimination and Preference in Transmission
Service
[[Continued from page 3082]]
[[Page 3083]]
reservation process or right of first refusal process. The Commission
explained that, when a longer-term request seeks capacity allocated to
multiple shorter-term requests, the shorter-term customers should have
simultaneous opportunities to exercise the right of first refusal. The
Commission also stated that, to minimize the potential for gaming, a
preempting longer request must be for a fixed capacity over the term of
the request. The Commission also revised section 13.2(iii) of the pro
forma OATT to more clearly distinguish between the use of the terms
``request'' and ``reservation'' for purposes of administering the right
of first refusal.
Requests for Rehearing and Clarification
808. TranServ contends that the Commission did not fully address in
Order No. 890 the procedures governing the right of first refusal
competition and its potential for gaming. If a longer-term request
initiates a right of first refusal competition among multiple shorter-
term customers, TranServ requests clarification of whether there should
be rounds of bidding and, if so, what the timing of that process should
be. TranServ also asks what should happen in the event that a longer
duration (not pre-confirmed) request is withdrawn in the middle of a
competition, i.e., whether those customers that opted to match are
allowed out of their longer duration reservations and whether those
that opted not to match are re-instated to their original capacity.
TranServ suggests that, before any preemptions are initiated, the
longer duration, higher priority request must be confirmed and locked
in with the competing customer before turning to the right of first
refusal rights holders and seeking their intent to match to preserve
their service priority. In addition to locking in the longer duration
customer prior to initiating preemption and right of first refusal,
TranServ argues that the transmission provider should be required to
provide a ``counter-offer'' matching request to the customer being
preempted that they may then elect to ignore or withdraw, or confirm to
retain their service priority. TranServ further questions what the
transmission provider's obligation is if the customer being preempted
exercises its right of first refusal by submitting a longer duration
request which cannot be granted without preemption of yet another
request.
809. TranServ also questions implementation of the right of first
refusal in the event transmission capacity is reassigned. Assuming that
a customer with a confirmed reservation for one week resells capacity
for one day, TranServ asks whether the reseller, the assignee, or both
have responsibility to match a competing longer-term request received
by the transmission provider. TranServ states that this issue was
considered by NAESB during WEQ discussions and that, during those
discussions, there was serious consideration given to not allowing the
resale of short-term firm prior to its unconditional deadline.
810. TranServ further questions what a shorter-term transmission
customer's obligation is if the longer-term service request only
preempts a portion of the short-term customer's service. TranServ
suggests that the term ``match'' in such instances be limited to an
exact match of duration with no option for the preempted customer to go
beyond those bounds and that the capacity of the match should be in the
amount that would need to be recalled from the preempted customer to
satisfy the longer duration request.
811. Duke argues that the right of first refusal regime for
transactions as short as one day for firm and one hour for non-firm is
overly complicated and will leave customers confused and unsatisfied as
to whether and when they can be assured that they have secured
transmission capacity. Duke provides detailed hypotheticals of the
right of first refusal competition process, arguing that the process is
cumbersome and could lead to anomalous and unwarranted outcomes. Duke
urges that the Commission place the following limits on the right of
first refusal: Require that matching requests be pre-confirmed and at
full tariff price, and that they be for the same amount (MW) and
duration as the competing requests; and, provide that rights of first
refusal are only offered when there is no impact on reservations that
are not on constrained interfaces. With these limitations in place,
Duke contends that the transmission provider will not have had to
entertain multiple right of first refusal rounds that in some instances
may leave capacity on the table and force customers to buy more service
than they may have required.
812. Bonneville seeks clarification as to how duration, pre-
confirmation status, price and time of response should be used to
determine the order in which the multiple, preempted shorter-term
requests may exercise the right of first refusal. By providing several
hypotheticals, Bonneville states that it cannot envision a circumstance
in which a right of first refusal is offered to a request when the
transmission provider does not have capacity to satisfy that request.
Bonneville requests that the Commission either delete the two sentences
in section 13.2(iii) of the pro forma OATT concerning this issue or
clarify how the transmission provider is expected to apply them.
813. Bonneville also requests clarification regarding which
customers have a right of first refusal under section 13.2 of the pro
forma OATT. Although the Commission amended the second sentence in
section 13.2(iii) of the pro forma OATT to grant eligible customers
with a ``reservation'' a right of first refusal to match longer-term
``requests,'' other sentences in that section still refer to preemption
of shorter-term ``requests'' for service instead of ``reservations.''
Bonneville states that this suggests that shorter-term requests
maintain a right of first refusal. Bonneville also contends that the
first sentence of section 13.2(iii), providing that ``requests'' for
longer term service may preempt ``requests for shorter term service''
up to specified deadlines, suggests that a longer duration request
simply preempts a shorter duration request, which is not offered a
right of first refusal. Bonneville argues that this would violate the
first-come, first-served rule, yet if the longer duration request is
offered a right of first refusal, it would contradict the amended
language of section 13.2(iii), under which only longer duration
``reservations'' have a right of first refusal.
Commission Determination
814. The Commission affirms the decision in Order No. 890 not to
change the ``first-come, first served'' nature of the reservation
process and the right of first refusal. These policies have worked well
in the past and, as we explain in Order No. 890, benefit transmission
providers and customers alike by facilitating the administration of the
reservation process and removing confusion about how to comply.
815. We disagree with Duke and TranServ that the right of first
refusal policies should be revised based on complex hypotheticals
involving the preemption of multiple short-term reservations. The
complexities pointed to by these commenters do not by themselves
warrant changing the right of first refusal rule. Even though we
recognize the potential for complexities to arise under the right of
first refusal rule, we believe them to be relatively limited. In the
off-chance that multiple eligible customers with short-term
reservations choose to exercise their right of first refusal for the
same capacity simultaneously, the Commission believes that they should
have a right to do so.
816. We therefore decline to expand upon the language of the pro
forma
[[Page 3084]]
OATT to account for every factual scenario that could arise under
sections 13.2 and 14.2 of the pro forma OATT. Sections 13.2 and 14.2 of
the pro forma OATT set forth adequate guidance for transmission
providers to fairly administer competing requests, including the
priorities for determining which reservations or requests trump one
another as well as the timeframes for eligible customers to respond to
competing requests. As noted above, we recognize that certain unique
cases can present difficult allocation issues, but conclude that these
extreme cases arise infrequently in the normal course of business. In
the vast majority of cases, we believe the right of first refusal rules
are efficient and easy to administer without further amending the
governing tariff language, as Bonneville and Southern suggest.
817. To the extent necessary, the Commission clarifies that a
``competing request'' under sections 13.2 and 14.2 of the pro forma
OATT may include a transmission service request that overlaps with only
part of another existing transmission service reservation since both
requests cannot be granted simultaneously. Accordingly, a ``competing
request'' for purposes of sections 13.2 and 14.2 may also include a
transmission service request for which transmission capacity cannot be
accommodated without preempting one or more existing transmission
reservations of parts thereof.
818. In response to TranServ and Duke, we clarify that sections
13.2 and 14.2 allow an eligible customer to retain its original
reservation by matching the competing service request's cost or
duration terms exactly or by exceeding one or more of the terms of a
competing transmission service request. Since any ``match'' by an
eligible customer in response to a potentially preempting request, by
definition, either exceeds the costs, duration or both of the eligible
customer's original reservation, we do not believe eligible customers
opting to match a competing request have a strong incentive, if any, to
``match'' a competing request with terms that exceed the competing
request. Nevertheless, we do not see any harm resulting from a match
that exceeds the exact terms of a competing request and therefore
believe it would not be appropriate to preclude the ability of eligible
customers to make such a request.
819. With regard to reassignments of capacity in the secondary
market, we clarify that the associated right of first refusal under
sections 13.2 and 14.2 of the pro forma OATT to match a competing
transmission service request applies to the primary transmission
service, not the reassignment of scheduling rights. Using TranServ's
example, the reassignment of one day of a customer's weekly service
would not cause the assignor or the assignee to match a competing three
day request for service since the initial one week reservation already
exceeded the competing request. The fact that one day of service has
been reassigned does not alter the assignor's entitlement to use
service for the remaining week reserved.
820. Finally, we grant rehearing to revise sections 13.2 and 14.2
of the pro forma OATT to clarify, as Bonneville requests, the terms and
obligations of sections 13.2 and 14.2 of the pro forma OATT.
5. Designation of Network Resources
821. In Order No. 890, the Commission addressed certain issues with
respect to the qualification, documentation and undesignation of
resources by a network customer. A number of petitioners request
rehearing and clarification of the Commission's rulings on these
issues. We address each of these issues in turn.
a. Qualification as a Network Resource
(1) LD Contracts
822. In Order No. 890, the Commission affirmed its existing policy
that a power purchase agreement may be designated as a network resource
provided it is not interruptible for economic reasons, does not allow
the seller to fail to perform under the contract for economic reasons,
and requires the network customer to pay for the purchase. The
Commission concluded that power purchases with a firm liquidated
damages (LD) provision may be eligible for designation as a network
resource if the contract obligates the supplier, in the case of
interruption for reasons other than force majeure, to make the
aggrieved buyer financially whole by reimbursing them for the
additional costs, if any, of replacement power. The Commission found
that the ``make whole'' LD provisions in the EEI firm LD product and
the WSPP Schedule C agreement satisfy this requirement.\308\
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\308\ The Commission further concluded that the WSPP Schedule C
agreement appeared to allow interruptions for reasons other than
reliability and, as a result, was ineligible for designation as a
network resource. The Commission exercised its discretion not to
invalidate existing designations of the WSPP Schedule C agreement
except under certain conditions. WSPP subsequently amended the
Schedule C agreement to expressly prohibit interruptions for reasons
other than reliability. See Western Systems Power Pool, 119 FERC ]
61,123 (2007).
---------------------------------------------------------------------------
Requests for Rehearing and Clarification
823. NCPA contends that the EEI Firm LD Product does not provide
recovery for certain types of penalties that a buyer may incur as a
result of non-delivery and, therefore, does not make buyers
sufficiently whole to justify designation as a network resource. NCPA
states that Section 1.51 of the EEI Firm LD Product prohibits the
reimbursement price from including ``any penalties, ratcheted demand or
similar charges.'' NCPA states that its contract with the California
ISO provides for significant penalties if NCPA operates outside of its
deviation band, but there is no avenue under the EEI Firm LD Product to
recover those costs if occasioned by a seller's failure to deliver.
824. NCPA also contends that the WSPP Schedule C contract fails to
explicitly allow buyers to recover their costs if they decide to cover
a non-delivery by running their own more expensive generation. NCPA
states that the issue has been discussed at WSPP meetings, but there
appears to be no clear consensus that sellers are obligated to pay
compensation for internal generation under the current language of the
agreement when it is more expensive than the market cost of power. NCPA
argues that this interpretation could be particularly problematic for
entities such as NCPA, as NCPA may prefer to run even very expensive
generation to avoid penalties imposed by the California ISO.
825. NCPA argues that the Commission established a clear and
straightforward standard that an LD clause was acceptable if it
required the buyer to be made whole in the event of a failure to
deliver. NCPA argues that the Commission can resolve the factual issues
by directing that these form contracts be amended to require sellers
who elect not to deliver (other than for force majeure) to make the
buyer whole in all respects, including contractual or market penalties
and the costs of the buyer operating its own resources.
826. Ameren argues that the Commission's decision that purchase
agreements containing make whole LD provisions can qualify as network
resources ignores reliability. Ameren maintains that the key issue is
whether such LD products can function as a resource to provide power,
not whether the power purchaser will be adequately compensated in the
event of a breach. Even with a make whole payment provision in place,
Ameren argues that it may still be in the economic interest of the
seller to interrupt delivery. While the Commission has appropriately
[[Page 3085]]
recognized that this self-interest warrants finding that other types of
LD contracts cannot be designated as network resources, Ameren contends
that the Commission fails to explain why it should not apply the same
standard to purchase agreements with make whole LD provisions.
827. Ameren also expresses concern that purchase agreements with
make whole LD provisions may be double-counted when determining
capacity, resulting in inadequate physical supplies to meet the
simultaneous capacity needs of all purchasers in the event replacement
power is needed. Ameren argues that allowing these types of contracts
to qualify as network resources is inconsistent with the pro forma OATT
because under such contracts there are no specific resources that can
be called on. Ameren questions whether LD products are sufficiently
firm to meet the applicable NERC or regional reliability council
requirements for firm resources or as capacity resources.
828. PJM raises a similar concern, asking the Commission to confirm
that firm power purchase agreements with make whole LD provisions do
not qualify as capacity resources in the PJM region even if they can be
designated as network resources under the pro forma OATT. PJM argues
that service as a capacity resource in the PJM region raises different
considerations than those addressed in Order No. 890.
829. Noting that parties often modify form agreements to suit their
particular transactions, Duke requests clarification that a purchase
based on the EEI Master Agreement qualifies as a designated network
resource only to the extent that the network customer has, in fact,
contracted for a firm resource that may be interrupted only for
reliability purposes. Duke also requests clarification that an
agreement that is not modeled after the EEI Master Agreement will
qualify as a designated network resource only if it provides for
delivery of a product similar to the EEI Firm LD Product (i.e., it
cannot be interrupted for economic reasons).
830. EPSA requests clarification that the Commission's statement in
Order No. 890 that firm LD contracts create for the buyer a contractual
right to generation was not intended to require that a firm LD contract
include a contractual right to the output of a specific generating
facility.
831. PNM seeks confirmation that a particular long-term power
purchase agreement between itself and Southwestern Public Service
Company (SPS) is eligible for designation as a network resource. While
the terms of this agreement allow for a specified level of curtailment
by SPS each month for any reason, the operating procedures governing
the agreement provide for curtailment and interruption only for system
emergencies. PNM argues that this agreement is therefore sufficiently
firm to be designated as a network resource.\309\
---------------------------------------------------------------------------
\309\ Citing Consolidated Edison v. Pub. Serv. Elec. & Gas Co.,
101 FERC ] 61,282 (2002).
---------------------------------------------------------------------------
Commission Determination
832. The Commission affirms the finding in Order No. 890 that the
make whole LD provisions in the EEI firm LD product and the WSPP
Schedule C agreement are sufficiently firm to make those agreements
eligible for designation as a network resource. In Order No. 890, the
Commission distinguished between LD provisions that make the aggrieved
buyer financially whole by reimbursing the additional costs, if any, of
replacement power and LD provisions that establish penalties at a
fixed-dollar amount, cap penalties at some level, or are otherwise not
equivalent to a general make whole provision.\310\ The Commission
explained that, under the latter type of LD provision, the seller need
only compare its savings from interruption with the specified LD
penalty when deciding whether to interrupt. The EEI firm LD product and
the WSPP Schedule C agreement make the buyer adequately whole and,
therefore, appropriately qualify for designation as a network resource.
---------------------------------------------------------------------------
\310\ See Order No. 890 at P 1453.
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833. With respect to the EEI firm LD product, section 1.51 of the
EEI Master Agreement defines the replacement price as either the
prevailing market price or, at the buyer's option, the price at which
the buyer purchases a replacement product plus costs reasonably
incurred in purchasing the substitute product and any reasonably
incurred transmission charges to deliver the product. While the
replacement price does not exclude penalties, ratcheted demand, or
similar charges, as NCPA points out, that does not mean a supplier has
inadequate incentives to deliver under the contract. The aggrieved
buyer is explicitly allowed to cover the costs reasonably incurred to
purchase a substitute product and, therefore, the seller must take into
consideration the buyer's actual cost of replacement power, which is
our principal concern.
834. With respect to the WSPP Schedule C product, the Commission
did not require that contracts make the buyer more than whole in the
event it chooses not to purchase less expensive energy available in the
market. Again, the Commission is concerned that suppliers providing
resources that have been designated by network customers take into
consideration the cost of replacing that power should the supplier
decide to interrupt. It is therefore adequate for a firm LD contract,
such as the WSPP Schedule C agreement, to provide for recovery of the
market price of replacement power in the event the buyer decides to run
its more expensive generation to cover the interruption.
835. We disagree with Ameren that allowing power purchase
agreements containing make whole LD provisions to qualify for
designation as network resources will compromise reliability. Firm
energy purchases need not be backed by capacity to qualify as network
resources since they are by definition firm, consistent with the
Commission's finding in Illinois Power.\311\ We appreciate Ameren's
concerns that system reliability be maintained and would not expect
double-counting of supplies to result from our designation rules. The
proper mechanism for addressing system reliability is through the
reliability standards, and not through restrictions on eligibility for
network resource status. The requirements for eligibility for network
resource status are intended to provide the proper incentives to
network customers designating network resources, and not to replace or
replicate reliability requirements.
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\311\ Illinois Power Co., 102 FERC ] 61,257 at P 14 (2003),
reh'g denied, 108 FERC ] 61,175 (2004) (Illinois Power).
---------------------------------------------------------------------------
836. Our decision is not, as Ameren claims, inconsistent with the
structure of the pro forma OATT. As the Commission acknowledged in
Order No. 890, there may be situations in which the supplier of a firm
LD product is presented with a net financial gain and has an incentive
to interrupt, but those incentives are similar to those faced by the
owner of a generating unit that has been designated as a network
resource.\312\ Ameren offers no reasons to require power purchase
agreements not tied to a particular generating unit to be more firm
than those that are in order to serve as a network resource under the
pro forma OATT.
---------------------------------------------------------------------------
\312\ See Order No. 890 at P 1454.
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837. We clarify in response to Duke that we are not concerned with
the particular form used to contract for resources. Each power purchase
agreement designated as a network resource must meet the relevant
requirements. Whether a contract meets
[[Page 3086]]
these requirements by being modeled after any specific form contract
has no bearing on whether the contract is eligible for designation as a
network resource. Consistent with Illinois Power, a firm LD contract
need not represent a contractual right to the output of any specific
generating facility. Whether or not such power purchase agreements may
serve as a capacity resource under PJM's Reliability Pricing Model
(RPM) is governed by the relevant RPM rules adopted by PJM, which were
not addressed in Order No. 890.
838. In response to PNM, we decline here to rule on whether a
particular purchase qualifies as a network resource because the
contract is not before us in this rulemaking. We reiterate, however,
that power purchase agreements that are not interruptible for economic
reasons may qualify for designation as a network resource. If the
binding rules governing a particular agreement allow the seller to
curtail or interrupt service only for system emergencies, then that
agreement would be eligible for designation as a network resource,
provided it complied with the remaining requirements of section 29.2(v)
of the pro forma OATT.
(2) Off-System Resources
839. In order to ensure that transmission providers have sufficient
information to determine the effect on ATC associated with the
designation of an off-system network resource, the Commission in Order
No. 890 modified section 29.2(v) of the pro forma OATT to specify
exactly what information must be provided to designate an off-system
network resource. As revised by Order No. 890, section 29.2(v) of the
pro forma OATT requires the following information to be provided with
the request and posted on OASIS when designating an off-system
resource: (1) Identification of the resource as an off-system resource;
(2) amount of power to which the customer has rights; (3)
identification of the control area from which the power will originate;
(4) delivery point(s) to the transmission providers' transmission
system; and (5) transmission arrangements on the external transmission
system(s). Additionally, Order No. 890 revised section 29.2(v) of the
pro forma OATT to require that the following information be provided
with off-system designations, but that such information must be masked
on OASIS to prevent the release of commercially sensitive information
including (1) any operating restrictions (periods of restricted
operation, maintenance schedules, minimum loading level of resource,
normal operating level of resource); and (2) approximate variable
generating cost ($/MWH) for redispatch computations.
Requests for Rehearing and Clarification
840. Duke argues that the Commission's finding that network
customers need only identify the control area from which power will
originate for an off-system resource is inappropriate in an era in
which many control areas encompass the transmission systems of multiple
operating companies. Duke requests rehearing, arguing that the
Commission should require network customers to provide more specific
information for multi-company systems (like Southern) or for ISOs or
RTOs. Duke argues that designations such as ``the Southern system'' or
``the PJM system'' do not provide sufficient granularity to accurately
model a transaction. Duke maintains that a network customer should at
least be required to specify the transmission system (e.g., Georgia
Power Company for Southern, or Dominion Virginia Power Company for PJM)
from which the power will originate.
841. Duke acknowledges that the Commission stated in Order No. 890
that transmission providers could seek amendments to their OATT via an
FPA section 205 filing if they believe that they face unique
circumstances that require deviations from the pro forma OATT to
require additional granularity in order to allow them to determine the
effects of designating network resources on ATC. Duke argues that this
is an inadequate response to the problem, stating that the standard for
receiving Commission approval of a variation from the pro forma OATT
has proved to be a significant bar. Duke also argues that transmission
providers could undermine consistency by developing different manners
in which to study and analyze such designations. Instead, Duke argues,
this issue ought to be resolved ``up front'' and on a consistent basis,
rather than in subsequent case-by-case skirmishes that may not provide
guidance for future disagreements.
842. TDU Systems disagree with Duke in their post-technical
conference comments, arguing that the requirement to identify the
control area within which an off-system resource is located provides
the appropriate balance. TDU Systems contend that identification of the
control area allows control area operators to calculate the effects on
ATC of the designation of an off-system resource while protecting
commercially sensitive information about the specific location of a
customer's generation resources. Southern agrees that (at least in the
Eastern Interconnection) requiring the identification of the ``control
area(s)'' gives the transmission provider sufficient information to
reliably plan its system while also providing the market with the
flexibility afforded by such off-system seller's choice contracts.
843. Several petitioners request clarification that specification
of the control area is not required within purchase agreements for
generators located off-system.\313\ These petitioners argue that only
the actual delivery point for power (which could be a physical
resource, a liquid trading hub, and interface point, or some other
location) is necessary for transmission system modeling purposes.
Information about the originating control area, they contend, is almost
never known with certainty at the time the request for designation as a
network resource is made and, therefore, requiring such specificity
will effectively invalidate such contracts as network resources.
Financial Service Joint Requestors and Idaho Power contend that such a
requirement could have serious adverse effects on liquidity,
competition, and risk management by limiting the ability of marketers
to participate in those markets, restricting resource options for LSEs.
Financial Service Joint Requestors maintain that participation in the
market by companies like its members augments the number of highly
creditworthy counterparties willing and able to supply power over mid-
to-long tenors to LSEs.
---------------------------------------------------------------------------
\313\ E.g., Financial Service Joint Requestors, Idaho Power,
Washington IOUs, and Morgan Stanley, joined by Barrick Goldstrike
Mines in its post-technical conference comments. Washington IOUs
also argues that the requirement to identify the originating control
area ``constitutes a direct restriction on the ability of a utility
to serve its bundled retail load, and thus violates the limitations
on the Commission's jurisdiction over transmission in bundled retail
transaction, citing Northern States Power Co. v. FERC, 176 F.3d 1090
(8th Cir. 1999) and Order No. 890 at P 92-94.
---------------------------------------------------------------------------
844. In their post-technical conference comments, Financial Service
Joint Requestors argue that the Final Rule's acceptance of LD contracts
conflicts with the requirement in section 29.2(v) to specify the
control area(s) from which the power is sourced, since an LD contract
may not provide that information. Financial Service Joint Requestors
also argue that Order No. 890 could be interpreted to allow a contract
to qualify as a network resource by identifying multiple control areas
of origin of the resource, although not the resource itself. Financial
Service Joint Requestors state that there is likely to be a wide range
of control areas from which power might ultimately be sourced and
listing each and every possible originating control area (such
[[Page 3087]]
as listing all 33 control areas in the Western Interconnection) seems
to be unduly burdensome and cumbersome.
845. APS and EEI, and Financial Service Joint Requestors, joined by
Southwestern Utilities in their post-technical conference comments,
argue that transmission providers should have discretion to waive the
requirement to provide originating control area information for
proposed network resources when such information is not needed or is
not meaningful for determining impacts on ATC. APS and EEI state that
it uses an approved rated path methodology to determine ATC, under
which the control area of an off-system purchase delivered to one of
its liquid trading hub border interfaces (Palo Verde or Four Corners)
has no effect on ATC calculations. APS and EEI state that this
contrasts with a flow-based ATC methodology, where the specification of
the originating control area can affect the ATC on a transmission
provider's system and, therefore, be necessary to calculate ATC. APS
and EEI argue that requiring the source control area for all purchased
power network resources will significantly reduce the liquidity of
physical power markets at Palo Verde and potentially elsewhere in the
West. APS and EEI argue that concerns about discrimination could be
addressed by directing transmission providers to post a
nondiscriminatory policy on its OASIS or directing NAESB to include
this issue in its business practices.
846. APS and EEI, and Southwestern Utilities agree, in their post-
technical conference comments, that the Eastern and Western
Interconnections have very different physical configurations, operating
modes and planning modes that have implications for the Commission's
rules for designating off-system network resources. In the Eastern
Interconnect, EEI argues, contract paths have little bearing on how
electrons actually flow, and thus it is critical for transmission
planners to know the location, at least at the control area level, of
the generation when reviewing requests to designate network resources.
In the Western Interconnection, which uses a rated path ATC calculation
methodology, APS and EEI, and Southwestern Utilities argue that
identification of the source generation for an off-system resource is
not important. EEI explains that the physical layout in the West is
more of a hub-and-spoke model where the only information required to
evaluate a request to designate a network resource is the point at
which power is delivered (often a trading hub). For these reasons, EEI
argues, seller's choice contracts are not appropriate for network
resource status in the Eastern Interconnection, but work well in the
Western Interconnection.
847. Pacific Northwest IOUs also agree, in their post-technical
conference comments, that it is not necessary in the Western
Interconnection for a transmission provider to know the source control
area of a remote resource in order to determine its effect on ATC,
since WECC path ratings incorporate parallel flows and other
operational conditions. Pacific Northwest IOUs state that it is only
necessary for a transmission provider in the WECC to know the border
location at which power will be delivered to its system in order to
determine the effect of the designation on ATC.
848. Morgan Stanley similarly argues, in its post-technical
conference comments, that, at a minimum, source control area
information for network resources should not be required in control
areas where participants agree that such information is not needed for
planning purposes. Morgan Stanley suggests that the Commission should
create a default approach that explicitly allows designations for off-
system network resources to not specify the resource location.
849. APS and EEI state, in its post-technical conference comments,
that the kinds of seller's choice contracts at issue (the WSPP Schedule
C contracts) are firm, physical contracts that require a seller to
deliver power at a specified location. Such contracts, APS and EEI
argue, are an important resource for most network customers, because
they are not unit contingent, and so sellers must find alternative
sources of power and continue to perform even in the event of an outage
of a particular generator. These contracts, APS and EEI contend, are
more dependable than contracts that specify a specific generator or
control area.
850. APS and EEI further contend that allowing flexibility of
supply when it does not adversely affect the transmission provider is
critical to maintaining liquid power markets in the West. The types of
contracts which are at issue, particularly when they are executed with
banks, allow physical transactions that could not otherwise occur due
to credit quality issues. If the banks conclude that the regulatory
constraints are too limiting and choose to move to a financial rather
than a physical approach to trading power, an important market, that is
currently available to APS and their customers, will be adversely
affected.
851. MISO and Duke oppose allowing a seller's choice contract that
does not meet all of the section 29.2 requirements to qualify as a
designated network resource. MISO argues that the specification of the
origin of supply resources or control area improves reliability in a
tightly interconnected grid. Duke agrees that, as amended, section
29.2(v) appropriately requires identification of the control area(s)
from which the power will originate. Duke argues, however, that there
is a facial conflict between this tariff requirement and the preamble,
which indicates that off-system seller's choice contracts may be
designated network resources. Duke maintains that, unlike a system sale
that designated a control area from which the power will originate, a
seller's choice contract does not require that power actually originate
from the control area designated.
852. Southern notes, in its post-technical conference comments,
that the more information that can be provided to the transmission
provider, the more accurately it can model its system and, in turn,
calculate ATC. Thus, Southern requests clarification that network
customers that have designated such an off-system seller's choice
contract as a network resource should provide to the transmission
provider as much information as the customer has regarding the actual,
underlying generating facilities from which the power will be sourced.
853. On rehearing, TDU Systems request clarification that a
``delivery point'' as contemplated by section 29.2(v) of the pro forma
OATT includes any point on an interface where deliveries are made. TDU
Systems argue that it is common in the industry to purchase a system
product from off-system and deliver that product to any interconnection
point on the interface between the system where the customer's native
load is embedded and the system in which the generation is sourced. TDU
Systems contend that this is how the term ``delivery point'' is used
throughout the industry generally and, in particular, in the NAESB WEQ
Glossary Subcommittee's Preliminary Draft Glossary which states that
``a delivery point can be a delivery node, an aggregation of delivery
nodes, an interface or trading hub.'' TDU Systems contend that NERC's
Glossary of Terms Used in Reliability Standards similarly contemplates
that a delivery point may include an interface, defining ``Point of
Delivery'' as ``a location * * * where an Interchange Transaction
leaves or a Load-Serving Entity receives its energy.'' TDU Systems
further argue that current RTO markets embrace the concept of
interfaces as delivery points, referring to a statement in section 30.2
[[Page 3088]]
of the PJM OATT that ``in the event that the Network Resource to be
designated will use interface capacity'' contemplates interfaces as
delivery points.
854. Several post-technical conference comments raised questions
regarding the need to specify a firm transmission path for the upstream
delivery of off-system firm LD contracts designated as network
resources.\314\ Morgan Stanley argues that sellers of firm LD contracts
typically hedge the risk of non-delivery by purchasing a portfolio of
paths and sources for supply. If a non-firm path is available that can
enable delivery of power used to source a designated network resource,
Morgan Stanley contends that the use of that path should be an option
for the seller. Morgan Stanley maintains that its experience has shown
that firm transmission is often no more reliable than non-firm
transmission and is often less reliable. By utilizing more flow
options, especially during high-load periods, Morgan Stanley argues
that existing transmission capacity is better utilized, as opposed to
forcing users into arbitrary firm paths.
---------------------------------------------------------------------------
\314\ E.g., Barrick Goldstrike Mines, Morgan Stanley, and
Southwestern Utilities.
---------------------------------------------------------------------------
855. Southwestern Utilities similarly request that network
customers only be required to specify transmission arrangements on
external systems from the point at which power is contractually
received to the delivery point specified on the transmission provider's
transmission system, rather than from the source generator or control
area. Sellers of firm LD contracts, Southwestern Utilities argue, would
frequently not be able to provide a description of the upstream
transmission arrangements on external transmission systems at the time
the sale to a network customer is made because, just as with control
area location, sellers are reluctant to limit their options well in
advance of delivery.
856. EPSA argues in post-technical conference comments that the
Commission should require the identification of neither the control
area, nor the point of delivery, for ``into'' firm LD products. To do
so would be, in EPSA's view, inconsistent with allowing firm LD
contracts to qualify for network resource designation without
identification of specific physical generation resources.
857. EPSA contends that, prior to the effectiveness of Order No.
890, LSEs have consistently been able to obtain network resource
designations for into-Entergy firm LD contracts, thereby ensuring that
the LSEs could rely on firm network transmission to deliver the energy
to their specific loads when their suppliers delivered energy into the
Entergy system. EPSA maintains that, beginning July 13, 2007, requests
to designate into-Entergy firm LD contracts as network resources, even
as daily network transmission, have been denied because LSEs have been
unable to provide Entergy with the source control area and information
about transmission arrangements associated with a firm transmission
reservation that will be used to deliver the firm LD contract.
858. EPSA explains that LSEs cannot provide this information
because, until the energy is scheduled, the LSE does not know the
source control area and transmission information. EPSA maintains that,
under the flexible terms of the firm LD contract, however, the seller
takes full responsibility for ensuring that the energy will be
delivered into the specified control area. EPSA states that source and
transmission arrangement information is provided when energy is
scheduled, and scheduling is made possible only because appropriate
transmission arrangements have been made. If a seller cannot make the
appropriate transmission arrangements to provide energy into the
Entergy system, EPSA explains, it will have defaulted on its contract
to deliver a firm product into Entergy. EPSA argues that, as noted in
Order No. 890, the liquidated damages resulting from such a default
makes the buyer whole providing the basis for the Commission's
determination that firm LD contracts can be designated as network
resources.
859. EPSA argues that, at a minimum, the Commission should clarify
that network customers are not required to provide information as to
source control area and transmission arrangements except on a day-ahead
basis when such information is made available through required
scheduling and tagging procedures.
860. On rehearing, Washington IOUs argue that any reliability
concerns the Commission might have about lack of control area
information at the time of designation is alleviated by the fact that
the tagging information provided with a schedule for a designated
resource contains all information to ensure reliability.
Commission Determination
861. The Commission affirms the decision in Order No. 890 to
continue to require identification of the control area in which an off-
system resource is located and the delivery point(s) to the
transmission provider's transmission system in order to designate the
resource as a network resource. Providing both the control area in
which the off-system resource is located and the delivery point(s) to
the transmission provider's system is usually sufficiently specific to
allow a transaction to be evaluated for its effects on ATC of the local
transmission system. As the Commission acknowledged in Order No. 890,
however, some transmission providers might need additional information
in order to determine the effects of designating off-system resources
on ATC and that such transmission providers could propose variations to
the pro forma OATT in an FPA section 205 filing.\315\ We continue to
believe that a generic rulemaking is not the appropriate venue to make
accommodations for system-specific issues faced by transmission
providers and, therefore, deny Duke's request to require more specific
information regarding the transmission system from which power will
originate.
---------------------------------------------------------------------------
\315\ See Order No. 890 at P 1481.
---------------------------------------------------------------------------
862. Similarly, we decline to generically relax the designation
requirements by eliminating the need to identify the source control
area for an off-system resource or delivery point(s) to the
transmission provider's transmission system. The Commission's policy
balances the need to accurately model transactions for ATC and related
purposes and the flexibility of a seller to source power from a range
of generators. We are unconvinced that identification of the source
control area and delivery point(s) is not needed to perform the ATC
analysis in every circumstance. We therefore reject requests to allow
designation of purchased power contracts that provide essentially no
advance information about the location or delivery of their power
sources. Waiting until the scheduling timeframe for tagging information
fails to address the up-front need for information in order to
accurately model ATC.
863. Several parties raise arguments relevant to local and regional
concerns that merit consideration, but a generic rulemaking is not the
appropriate venue to address such concerns. Transmission providers that
believe that their circumstances warrant a variation from the
designation requirements of the pro forma OATT may make a proposal
under section 205 of the FPA. We have already approved one such request
for Puget Sound Energy, Inc., conditioned on that company demonstrating
that its tariff variation continues to be
[[Page 3089]]
appropriate after the ATC standardization process is complete.\316\
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\316\ See Puget Sound Energy, Inc., 120 FERC ] 61,232 (2007);
see also Arizona Public Service Company, 121 FERC ] 61,246 (2007).
---------------------------------------------------------------------------
864. We disagree with Financial Service Joint Intervenors'
contention that there is an inconsistency between the requirement in
section 29.2(v) of the pro forma OATT that the network customer
identify the control area from which power is sourced and the finding
in Order No. 890 that firm LD contracts are eligible for designation as
network resources. The Commission did not state that every firm LD
contract can be designated as a network resource, but rather that they
are eligible for designation. Such contracts must also comport with the
other requirements of section 29.2 of the pro forma OATT, including
identifying the control area from which the power will originate, to
actually be designated as a network resource. A seller's choice firm LD
contract therefore cannot be designated until the source control area
is disclosed by the seller.\317\ The Commission's discussion of
particular aspects of firm LD contracts does not mean that remaining
requirements of section 29.2 no longer apply.
---------------------------------------------------------------------------
\317\ See Order No. 890 at P 1481 (requiring identification of
source control area, rather than more specific transmission system,
prior to designation of off-system seller's choice contracts).
---------------------------------------------------------------------------
865. We decline to grant Southern's request to generically require
that network customers provide as much information as they have
regarding the actual, underlying generating facilities from which power
will be sourced for an off-system seller's choice contract. We
encourage network customers to share such information when they have
it, and encourage transmission providers to develop business practices
to establish procedures through which network customers can provide
such information, but conclude that a formal requirement would be
cumbersome to administer and enforce. We believe that the existing
requirements generally provide sufficient information to evaluate a
designation request.
866. Section 29.2(v) of the pro forma OATT requires identification
of the ``delivery point(s) to the transmission provider's transmission
system.'' To the extent necessary, we clarify that the term ``delivery
point'' does contemplate an interface between the local transmission
provider's transmission system and the neighboring transmission system
from which power is being received. In response to Financial Service
Joint Intervenors, we clarify that the use of the plural ``control
area(s)'' in the revisions to section 29.2(v) adopted in Order No. 890
was inadvertent and amend that language accordingly in this order. We
disagree that a network customer could satisfy the requirements of
section 29.2(v) by identifying multiple control areas, such as all 33
control areas in the Western Interconnection, from which a particular
transaction could be sourced.
867. In response to Barrick Goldstrike Mines, Morgan Stanley, and
Southwestern Utilities, the Commission clarifies that the requirement
in section 29.2(v) of the pro forma OATT to identify the transmission
arrangements on external systems applies to the transmission leg from
the resource being designated to the transmission provider's
transmission system. If an off-system power purchase is sufficiently
firm to satisfy the designation requirements, then the transmission
provider need not be concerned with the upstream transmission leg(s)
from the generator(s) to the point where the buyer takes title of the
firm power. Because the contract itself is the resource being
designated, and that contract is firm in nature, it is not necessary to
demonstrate the firmness of the upstream transmission in order to
designate the contract as a network resource.
(3) On-System Resources
868. In response to a commenter request, the Commission clarified
in Order No. 890 that a customer may not designate as a network
resource a seller's choice power purchase agreement that is sourced by
generating units internal to the transmission provider's control area,
since evaluating the effect on ATC would be problematic. The Commission
stated that, if a customer wishes to have a choice of resources that
are internal to the particular transmission provider's control area
from which to dispatch power, it must designate each of the resources
as network resources. The Commission did not specifically address on-
system system sales (i.e., purchases from a specified generation
system).\318\
---------------------------------------------------------------------------
\318\ The Commission proposed in the NOPR to maintain its
current policy of allowing network customers to designate resources
from system purchases not linked to a specific generating unit. See
NOPR at P 407.
---------------------------------------------------------------------------
Requests for Rehearing and Clarification
869. Various concerns were raised in post-technical conference
comments regarding a possible interpretation of Order No. 890 as
prohibiting the designation of on-system system sales as network
resources.\319\ Some argue that such an interpretation would be
inconsistent with statements in the NOPR and Order No. 890 that, when a
network customer is designating a system purchase as a new network
resource, the source information required in section 29.2(v) should
identify that the resource is a system purchase and should identify the
control area from which the power will originate.\320\ Given this
discussion in Order No. 890, TAPS and APPA argue that the deletion of
language requiring ``description of purchased power designated as a
Network Resource including source of supply, Control Area location,
transmission arrangements and delivery point(s) to the Transmission
Provider's Transmission System'' from section 29.2(v) of the pro forma
OATT may have been inadvertent. TAPS and APPA state that they are
unaware of any party having argued against the eligibility of on-system
system sales for designation as network resources and that, given the
absence of any indication of a problem with these types of contracts,
the Commission should not implement such a policy.
---------------------------------------------------------------------------
\319\ E.g., Alabama Municipal, Hoosier, and TAPS and APPA.
\320\ See NOPR at P 408; Order No. 890 at P 1435.
---------------------------------------------------------------------------
870. Alabama Municipal argues in its post-technical conference
comments that designation of on-system system sales as network
resources does not contribute to difficulties in computing ATC. Alabama
Municipal argues that system sales contracts do identify the source of
power: the seller's whole generation fleet. Others argue in post-
technical conference comments that, because system power is what
utilities use to supply retail load, wholesale system power cannot do
any more harm to ATC calculations than the utility's service to its
retail customers.\321\
---------------------------------------------------------------------------
\321\ E.g., Alabama Municipal, Hoosier, NRECA
---------------------------------------------------------------------------
871. Wisconsin Electric argues that stand-alone transmission
providers and RTOs should be allowed to have different rules regarding
the designation of on-system system sales as network resources.
Wisconsin Electric contends that within MISO, for example,
deliverability studies are performed for each resource to assess
whether the designated capacity is deliverable to the MISO system and
that, once that deliverability test has been satisfied, another load
within MISO is able to designate the same resource as a network
resource. Wisconsin Electric further states that energy may not
actually be delivered from a designated resource in a particular hour
due to MISO decisions on which units are dispatched on an hour-by-hour
basis.
[[Page 3090]]
872. Others argue in post-technical conference comments that
prohibiting the designation of on-system system sales as network
resources and requiring the designation of specific generating capacity
would not be comparable to the way the transmission provider operates
when serving its load.\322\ Some contend that making system products
more difficult to use is contrary to the Commission's policy of
encouraging and facilitating use of long-term contracts and contrary to
the Commission's obligations under section 217(b)(4) of the FPA.\323\
---------------------------------------------------------------------------
\322\ E.g., Alabama Municipal, Hoosier, TDU Systems, and TAPS
and APPA.
\323\ E.g., Great Lakes, Hoosier, TDU Systems, and TAPS and
APPA.
---------------------------------------------------------------------------
873. Many of the post-technical conference comments raise concerns
regarding the burdens that would be imposed on customers if they were
forced to re-structure their system purchase contracts in order to
micromanage the designation of their network resources. There is
general agreement that customers would be subject to unauthorized use
penalties and would lose the benefits of purchases from system products
if they were required to designate particular units within the seller's
system.\324\ In their view, requiring identification of each individual
generating station with fixed amounts of generation and fixed amounts
of delivery would be chaotic and overwhelming and would diminish
reliability.
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\324\ E.g., Alabama Municipal, Duke, Great Lakes, Hoosier,
Kansas Power Pool, NRECA, PNGC Power, TAPS and APPA, TDU Systems,
and Wisconsin Electric. PPL Parties also appear to support allowing
on-system system sales to be designated as network resources. PPL
Parties state that they support allowing designation of on-system
``seller's choice'' contracts, but their comments about increased
reliability and reduced costs when service is provided by a ``fleet
of generators'' suggest they are specifically in support of allowing
designation of on-system system sales, and not necessarily on-system
seller's choice contracts. Southern also argues that system sales
should be allowed to be designated so long as the underlying
generating facilities are individually capable of receiving firm
transmission service during the period of designation.
---------------------------------------------------------------------------
874. TDU Systems and TAPS and APPA argue in their post-technical
conference comments that, if on-system system sales are not allowed to
be designated as network resources, customers will be motivated to seek
off-system system products instead, leading to pancaked transmission
rates and the loss of local transmission providers as possible
suppliers. TDU Systems also argue that disallowing on-system system
sales to be designated as network resources would, in some areas,
diminish the ability of the wholesale transmission-dependent utility
systems that provide virtually the only competition in retail
electricity markets before Order No. 888 to compete effectively. TAPS
and APPA state that an alternative would be for the on-system seller to
be the network customer and take on (or possibly avoid) the headache of
designating and undesignating resources. TAPS and APPA argue that this
would be practical, however, only if the network customer desires full-
requirements system power and that customers seeking to use other
resources in combination with the system power (as many transmission
dependent utilities do) would not have this option. TAPS and APPA also
point out that customers may own transmission facilities for which,
under the Commission's policy, credits are to be provided only where
the owner of the transmission assets is the network customer itself.
TAPS and APPA therefore conclude that a transmission dependent utility
may have good reason to want to be the network customer, rather than
allowing the transmission provider to assume that role.
875. Great Lakes supports TAPS and APPA's position in its post-
technical conference comments, adding that requiring transmission
dependent utilities to be full-requirements customers of a system power
seller would effectively shut out entities that do not exclusively
utilize full-requirements system power contracts. Great Lakes adds that
transmission dependent utilities have begun to develop the requisite
expertise required to allow them to compete more effectively in the
wholesale market and should not be required to give up those benefits
in order to utilize system power contracts.
876. Several petitioners argue that system sales contracts are not
the same as seller's choice contracts.\325\ These petitioners argue
that typically a seller's choice contract involves a situation where,
under certain delineated circumstances, a seller that would normally
sell power to the purchaser from one unit may choose to deliver power
from an alternate unit. These petitioners argue that the Commission's
ruling in Order No. 890 regarding the eligibility of seller's choice
contracts does not affect the eligibility of system sales.
---------------------------------------------------------------------------
\325\ E.g., NRECA, TDU Systems and Wisconsin Electric. Duke
Energy Carolinas and Hoosier make similar arguments in their post-
technical conference comments.
---------------------------------------------------------------------------
877. Duke Energy Carolinas contends in its post-technical
conference comments that the requirement in section 29.2(v) to provide
the delivery point for a resource sourced from purchased power could be
interpreted to require either an interface delivery point or a local
load delivery point. For system purchases that are sourced by
generators in the same control area as the load, Duke Energy Carolinas
argues, the only delivery point is the location of the load. Duke
Energy Carolinas states that a network load may have more than one load
delivery point, but all such points are where some network load is
located. Duke Energy Carolinas also distinguishes system sales from
seller's choice contracts, which it states allow the seller to select
on a daily basis the source of the physical power. Duke Energy
Carolinas contends that system sales do not fit within this category of
seller's choice contracts since the source control area is known and
there is no ``choice'' as to which units will be used to serve a
network customer's load, given that units are dispatched according to
economic and reliability dispatch principles.
878. Duke Energy Carolinas also argues that disallowing on-system
system sales would be inconsistent with the Commission's longstanding
practice of accepting network integration transmission service
agreements with designated network resources such as ``Seller's
Generation System'' or ``Contract with Seller'' with no concern about
transmission providers calculating ATC. Duke Energy Carolinas further
argues that disallowing on-system system sales would be inconsistent
with allowing at least some wholesale customers to be classified as
native load customers and permitting the seller to serve such native
load customers from a choice of all of its network resources. If the
Commission does not allow on-system system sales to be designated as
network resources, Duke Energy Carolinas requests clarification of
whether a wholesale customer that entered into an on-system system
purchase contract with a transmission provider prior to July 13, 2007
can continue to designate the contract as a network resource. Duke
Energy Carolinas also requests various other clarifications regarding
the designation of system sales as network resources.
879. TAPS and APPA state that, while the pro forma OATT does not
now appear to require it, they would not object to a requirement that
every network customer, as well as the transmission providers and
merchant affiliates, seeking to designate on-system system sales (or
generation fleet) list the generators in the portfolio that stands
behind it, provided that this not
[[Page 3091]]
translate to a requirement to assign particular generators or amounts
to serve the contract. These petitioners argue that the location of the
generators, which presumably the transmission provider knows anyway,
ought to be enough to permit the transmission provider to determine
whether the system sale can be delivered to the customer and, thus,
whether the designation of the network resource can be accepted.
880. Bonneville argues that, because of the interconnected nature
of a hydroelectric power system, it cannot make power sales from
particular generating units and, therefore, all of its sales are system
sales. Bonneville states that the federal hydroelectric projects in the
Pacific Northwest are multi-purpose projects and that the operators
(the United States Corps of Engineers and Bureau of Reclamation) cannot
dedicate a given hydroelectric project to generate a given amount of
power every hour to serve a given contract or for any other purpose.
Bonneville states that almost 100 of its customers take network
transmission service and have included Bonneville system purchases of
power as network resources. Bonneville also notes that, under the
Northwest Power Act, it is obligated to sell electric power to each
Northwest utility to meet the firm power load, to the extent that the
utility's firm power load exceeds its resources.\326\ Bonneville
maintains that nothing in the Northwest Power Act contemplates sales
out of, or rates based on, individual resources, and that all of
Congress's directives treat federal generation as a whole and make no
distinction based on the individual resource. Bonneville argues that it
has addressed the ATC issues that the Commission has identified through
its AFC methodology. PNGC Power and PPC express support in their post-
technical conference comments for Bonneville's general position with
respect to the designation of on-system system sales from the
Bonneville's hydroelectric system.
---------------------------------------------------------------------------
\326\ 16 U.S.C. 839a(10).
---------------------------------------------------------------------------
881. Several of the post-technical conference comments address the
eligibility of on-system seller's choice contracts to be designated as
network resources. Southern states that it generally opposes allowing
on-system seller's choice contracts to be designated on a long-term
basis, but acknowledges that such contracts might be designated on a
short-term basis. Southern states that many seller's choice contracts
require the source to be named at least on a day-ahead basis. Southern
states that it would be acceptable to designate such resources on a
short-term basis once the delivery source is identified.
882. Kansas Power Pool, however, argues, in its post-technical
conference comments, that all seller's choice contracts should be
eligible to serve as network resources. Kansas Power Pool argues that
it is the supplier, not the customer, of a seller's choice contract
that enjoys the flexibility to select resources or to determine which
resources will or will not be dispatched.
883. Some post technical conference comments argue that seller's
choice contracts from on-system generation located in an unconstrained
system or zone (i.e., an area within which there are no internal paths
for which ATC is calculated) should be eligible for network resource
status.\327\ Conversely, Duke Energy Carolinas and EEI argue that, if a
system or zone has congestion (i.e., internal ATC paths), then unit
designation becomes necessary to be able to correctly calculate ATC.
South Carolina E&G argues that unconstrained transmission systems could
become constrained over time, but any possible need for the designation
of network resources to assist in calculating internal ATC will be
observable on OASIS. South Carolina E&G argues that a transmission
provider has no incentive to overstate ATC, so the Commission can be
assured that designation of network resources is unnecessary if OASIS
shows no constraints, and vice versa.
---------------------------------------------------------------------------
\327\ E.g., Duke Energy Carolinas, EEI, Pacific Northwest IOUs,
South Carolina E&G, and Southwestern Utilities.
---------------------------------------------------------------------------
884. Other post technical-conference comments oppose the proposal
for unconstrained transmission areas, at least as applied to on-system
system sales, arguing that the proposal appears to be motivated by the
incorrect assumption that the Commission in Order No. 890 found that
both on-system seller's choice contracts and on-system system sales are
eligible for designation as network resources.\328\ With regard to
seller's choice contracts, Hoosier and TDU Systems argue that adopting
an unconstrained transmission area approach would leave those LSEs
unfortunate enough to be located on constrained systems without the
transmission rights they had prior to Order No. 890. Hoosier and TDU
Systems argue that ATC would not be limited unless the transmission
provider has failed to expand its system to meet the needs of its
network customers, pointing to TLR statistics to emphasize concerns
regarding particular transmission providers. Hoosier contends that
restricting seller's choice contracts to particular areas of the
transmission provider's system would assume the existence of
constraints on a system to such a degree that the long-held rights of
network customers to designate their historical resources as network
resources would be eliminated. Hoosier and TDU Systems believe that the
Commission's policy should assume transmission providers have been
planning and expanding their systems appropriately, putting the burden
on the transmission provider whose system is so constrained that it
cannot evaluate internal ATC to make a filing proposing changes to its
OATT to accommodate their problems. Acceptance of the unconstrained
transmission area proposal, they argue, would be inconsistent with the
Commission's obligations under FPA sections 217. Hoosier and TDU
Systems argue that the transmission provider should experience no more
difficulty in calculating ATC for its network customers than it does to
serve its own retail native load.
---------------------------------------------------------------------------
\328\ E.g., TAPS and APPA.
---------------------------------------------------------------------------
Commission Determination
885. In the NOPR, the Commission proposed to continue to allow
resources from system purchases not linked to a specific generating
unit to be designated as network resources.\329\ The Commission did not
specifically address on-system system sales in Order No. 890, focusing
instead on on-system seller's choice contracts.\330\ Thus, the
Commission's existing policies regarding the eligibility of on-system
system sales for network resource status were not affected by the
reforms adopted in Order No. 890.
---------------------------------------------------------------------------
\329\ See NOPR at P 407.
\330\ See Order No. 890 at P 1483.
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886. Various concerns have nonetheless been expressed regarding the
treatment of on-system system sales in requests for rehearing and
clarification and at the technical conference held by Commission staff
on July 30, 2007 and in subsequent comments. TAPS and APPA, for
example, question whether the revisions to section 29.2(v) of the pro
forma OATT adopted in Order No. 890 were intended to alter the
designation requirements for on-system system sales. Alabama Municipal
and Wisconsin Electric argue that the Commission's concerns regarding
the accuracy of ATC calculations are not relevant in the context of
system sales. In order to respond to these concerns, and provide
guidance to the industry, we clarify that Order No. 890 was not
intended to change the requirements for
[[Page 3092]]
designating on-system system sales as network resources under the pro
forma OATT.\331\
---------------------------------------------------------------------------
\331\ Slice-of-system sales are a type of system sale and,
therefore, our discussion below regarding on-system system sales
applies equally to on-system slice-of-system sales, as well as
system sales from hydroelectric systems.
---------------------------------------------------------------------------
887. Prior to Order No. 890, section 29.2(v) of the pro forma OATT
did not distinguish between the designation of on-system and off-system
resources. In order to designate a network resource, the network
customer was required to provide information regarding the unit size,
the amount of capacity being designated, VAR capability, operating
restrictions, approximate variable cost, and arrangements governing the
third-party sales and deliveries. For off-system power purchases,
information was also required regarding the source of supply, control
area location, transmission arrangements, and delivery point(s) to the
transmission provider's system. These various requirements were stated
in a single series of bullets in section 29.2(v).
888. In Order No. 890, the Commission restructured section 29.2(v)
to more clearly identify the information that must be provided for on-
system resources and off-system resources, breaking apart the series of
bullets into two separate lists. The basic requirements of designation
remain the same, except that the tariff language more clearly specifies
the information (i.e., source of supply, control area location,
transmission arrangements, and delivery point(s) to the system) that
applies only to off-system resources. This was implicit in the prior
tariff formulation, since the underlying information related to off-
system transactions. The Commission sought to more explicitly state the
information required under section 29.2(v) to facilitate compliance
with the new obligation for customers to provide an attestation that
the requirements for designation as a network resource have been met
for the particular resource being designated.
889. These changes to the pro forma OATT therefore did not change
the substantive requirements for designating network resources as they
apply to on-system and off-system resources. For on-system resources,
network customers must continue to provide the same information in
their designation request: the unit size, the amount of capacity being
designated, VAR capability, operating restrictions, approximate
variable cost, and arrangements governing the third party sales and
deliveries. We understand that it is common practice in the industry
for transmission providers to consider the identification of the source
system for an on-system system sale sufficient to provide this
information, since the transmission provider already has the necessary
information for constituent generators on the system given that the
units supporting the system sale have otherwise been designated for use
by network or native load.\332\ Nothing in Order No. 890 imposed new
information requirements on transmission providers that previously
deemed the requirements of section 29.2(v) fulfilled by the
identification of the source system for an on-system system sale.
Network customers may therefore continue to designate such resources as
appropriate.
---------------------------------------------------------------------------
\332\ It may be the case that identification of another system
within the transmission provider's control area, such as a fleet of
merchant generators, would trigger the need for additional
information under section 29.2(v). That type of transaction,
however, does not appear to be of concern to petitioners and thus we
do not address it here.
---------------------------------------------------------------------------
890. To the extent there are concerns regarding the effect of
designating on-system system sales on ATC, we note that transmission
providers have been directed to address the effect on ATC of
designating and undesignating network resources as part of the on-going
NERC/NAESB standardization effort.\333\ Through that process,
transmission providers will develop consistent methodologies for
calculating the effect on ATC of designation resources, both on-system
and off-system. Until the standardization process is complete, however,
the Commission cannot know whether additional information is required
in order to accurately model the designation of an on-system system
sale. We will revisit the requirements of section 29.2(v) as necessary
after the NERC/NAESB ATC standardization effort is complete. Until such
time as those requirements change, transmission providers should
continue their existing practices regarding the designation of on-
system system sales as network resources. Further clarification as
requested by Duke is not necessary.
---------------------------------------------------------------------------
\333\ See Order No. 693 at P 1041.
---------------------------------------------------------------------------
891. The Commission affirms the finding in Order No. 890 that on-
system seller's choice contracts generally do not provide enough
information to satisfy the requirements for designation as a network
resource. For on-system resources, the location of the capacity is
necessary for determining the effect of a proposed designation on
transmission capacity, both for evaluating the acceptability of the
resource itself, and for allowing future transmission service requests
to be evaluated. We agree with Southern, however, that a contract that
may not provide enough information provided to be designated as a
network resource at one time may become eligible for designation as the
information becomes available. For instance, if a day before scheduling
the seller were to identify source generation for a seller's choice
contract for the following day, and if the contract were to bind the
seller to use the newly identified generation (at least for the period
that it was identified), then the resource would be eligible to be
designated for the period during which the source information is firm
(provided the resource complied with all other relevant requirements).
At that point, the agreement is effectively no longer a seller's choice
contract for the specified period. If, on the other hand, the seller
identifies only what it intends to source the power with, but no
contractual mechanism prevents the seller from sourcing the power from
an alternative source prior to scheduling, then the resource would
remain a seller's choice contract and would not be eligible for network
resource status.
892. We disagree with Kansas Power Pool's argument that, because it
is not the customer that has the flexibility to select the generation
in a seller's choice contract, such contracts should be eligible for
network resource status. It is the inability to evaluate or determine
the proper transmission reservations for on-system seller's choice
contracts that is concerning, and not the fact that it is the seller or
the buyer who has the ``choice'' of how to dispatch the power.
893. With regard to the proposal to allow the designation of on-
system seller's choice contracts within unconstrained transmission
areas, we believe that our clarification above that Order No. 890 did
not change the Order No. 888 requirements for designating on-system
system sales will alleviate most of the concerns expressed by
supporters of this proposal.
(4) Resource Information
894. In Order No. 890, the Commission affirmed the requirement that
customers designating a network resource must provide a description of
the resource (current and 10-year projection) including, among other
things, approximate variable generating cost ($/MWH) for redispatch
computations and any operating restrictions.
Requests for Clarification and/or Rehearing
895. EEI requests clarification that the operating restrictions
information required by section 29.2(v) of the pro forma OATT need not
be provided for
[[Page 3093]]
off-system system sales if that information is not contained in the
relevant contracts. EEI also suggests that the variable price of energy
specified in the contract and not the actual variable costs of the
units that supply the sale serve as the variable generating cost for
redispatch computations. EEI argues that the network customer generally
will not know the actual variable cost and that the price specified in
the contract is the relevant price for purposes of redispatch, since
that is the cost that the network customer will incur or avoid if its
contract is redispatched up or down. Bonneville and Duke Energy
Carolinas question in their post-technical conference comments what
variable costs should be provided for on-system system sales. Duke
Energy Carolinas states that the contract energy price is used as the
approximate variable generating cost for redispatch purposes.
896. EPSA requests clarification that network customers are not
required to provide a redispatch cost for a firm LD contract, since
such contracts are effectively take-or-pay contracts and cannot, for
example, provide a source of incremental energy if Entergy is surveying
redispatch options to address a reliability event. EPSA argues that the
fact that not all network resources are suitable for redispatch options
is not unusual, since many units may be must-run in order to meet
reliability needs (such as voltage support) or contractual requirements
(such as QF purchases), or to reflect operating characteristics (such
as nuclear units that cannot be cycled off and on quickly). EPSA is
concerned that some transmission providers may believe that the
supplier of a firm LD contract is required to provide the network
customer with a contract-specific variable redispatch cost based on its
own supply alternatives which, as noted, is not possible. EPSA argues
that a determination that designation requests could be rejected for
lack of information that is not relevant to such contracts would be
contrary to the Commission determination that firm LD contracts can
serve as network resources.
Commission Determination
897. The Commission clarifies in response to EEI that the operating
restrictions applicable to off-system system sales designated as
network resources are the restrictions set forth in the relevant
contracts, not the underlying units supplying the contracts. Similarly,
the approximate generating cost for redispatch purposes for a system
sale is the variable energy cost specified in the contract.
898. We disagree with EPSA that a network customer should not be
required to provide a redispatch cost for a firm LD contract. When a
network customer designates a network resource, it agrees under section
30.5 of the pro forma OATT to redispatch its resource as requested by
the transmission provider pursuant to section 33.2 of the pro forma
OATT. A firm LD contract is like any other resource, redispatchable by
the transmission provider within the customer's rights to the resource,
as stated in the contract.
(5) General
899. In Order No. 890, the Commission determined that firm point-
to-point service provided on a conditional firm basis is sufficiently
firm to be used for transmission to import an off-system designated
network resource. The Commission also denied a request to require the
validity of network resource designations to be verified by the seller
or owner of the generation, finding that such a verification is
unnecessary in light of the new attestation requirements. Finally, the
Commission clarified that the minimum term for designations of new
network resources should be the same as the minimum term used for firm
point-to-point service (i.e., daily), unless otherwise demonstrated by
the transmission provider and approved by the Commission.
Requests for Rehearing and Clarification
900. Duke seeks clarification that network customers that designate
off-system resources supported by conditional firm point-to-point
transmission service are required to have in place or obtain from the
transmission provider reserves or backup resources to cover the periods
when the conditional firm point-to-point transmission service is not
available.
901. Indicated Commenters argue that a network customer designating
a generating unit that it does not own should have an obligation to
provide contemporaneous notice of the designation to the owner of the
generating unit. Indicated Commenters argue that such notice should
indicate, at a minimum, the amount of capacity claimed to be under
contract and the duration of the claimed contractual right. Indicated
Commenters argue that their proposed notice requirement is appropriate
since designation as a network resource may subject the generation
owner to certain must-offer requirements (in organized markets) or
redispatch orders (in non-organized markets). Indicated Commenters also
contend that such a notice requirement would facilitate enforcement of
the OATT requirements by ensuring that generators are not obligated
without their knowledge and that false or questionable designations are
identified promptly. Indicated Commenters argue that the current system
of audits and increased penalty authority and other sanctions will have
some deterrent effect, but that it will do nothing to make generation
owners and other users of the transmission system whole after
violations occur.
902. Pacific Northwest Parties, joined by PPC in its post-technical
conference comments, requests clarification that, to the extent a
transmission provider establishes a minimum term for designation of
network resources, it need not be the same as the minimum term offered
by the transmission provider for firm point-to-point service. Pacific
Northwest Parties argue that this clarification will promote hourly
firm energy markets by allowing transmission providers to offer hourly
firm point-to-point transmission service even if they cannot
accommodate a one-hour minimum term for designation of network
resources.
903. Reliant asks in its post-technical conference comments that
the Commission carefully consider any variations from the network
service requirements of the pro forma OATT proposed by RTOs and ISOs in
their compliance filings. Reliant contends that requirement for proper
identification of network resources is intended to ensure that
transmission reserved for firm network use is used only to deliver
properly designated network resources and that no more than one LSE has
identified the same resource capacity as serving its load (i.e., to
avoid double-counting). Reliant asks the Commission to ensure that any
variations from the pro forma OATT proposed by RTOs and ISOs similarly
prevent double-counting.
Commission Determination
904. The Commission declines Duke's request to require that a
network customer, as a condition of designating off-system resources
supported with conditional firm point-to-point transmission service,
have in place or obtain from the transmission provider reserves or
backup resources to cover the periods when the resource supported with
conditional firm point-to-point transmission service might not be
delivered. Duke appears to misunderstand the nature of conditional firm
service. A network customer utilizing conditional firm service would be
using firm transmission service
[[Page 3094]]
except during the limited periods where such service is conditional.
Transmission service for those resources could be curtailed during such
periods, similar to how secondary network service may be curtailed
prior to curtailment of other firm transactions. In the event
conditional firm service is curtailed, the network customer would be
required to serve its network load from other resources, just as when
the transmission provider curtails the network customer's use of
secondary network service. It is not the responsibility of the
transmission provider to ensure that the network customer has
sufficient resources to meet its load.
905. We disagree with Indicated Commenters that network customers
should be required to serve notice on sellers of power that is
designated as a network resource. The obligation to comply with the
designation requirements applies to the network customer, not the
resource owner. The appropriate place to impose obligations on the
resource owner is in the contract governing the sale. To the extent a
contract has been executed that meets the requirements for network
resource designation, it is not clear why the seller would be affected
by the actual designation of the resource, since the network resource
redispatch obligations do not go beyond the amount of power that is
available under the contract as designated by the network customer. If,
as Indicated Commenters argue, there are unique considerations in some
organized markets, a generic rulemaking is not the appropriate venue to
make accommodations for such system-specific issues.
906. We also decline to grant the request of Pacific Northwest
Parties to generically allow transmission providers to establish a
minimum term for designations of network resources that is not the same
as the term for firm point-to-point service. Pacific Northwest Parties
do not explain why a transmission provider could accommodate hourly
point-to-point transmission service, but not hourly network service. To
the extent that a transmission provider has specific circumstances that
justify adoption of a different minimum term for network resource
designations, it should raise them in the context of an FPA section 205
filing.
907. To the extent Reliant or any other party has a concern
regarding an RTO or ISO's compliance with the requirements of Order No.
890, the appropriate forum to consider those concerns is on review of
the underlying compliance filing.
b. Documentation for Network Resources
908. The Commission concluded in Order No. 890 that transmission
providers should be responsible for verifying that third-party
transmission arrangements to deliver an off-system designated network
resource to the transmission provider's system are firm. However, the
Commission found that transmission providers should not be responsible
for verifying that the generating units and power purchase agreements
designated as network resources satisfy the requirements of section
30.1 and 30.7 of the pro forma OATT. The Commission instead required
network customers and the transmission provider's network function to
include a statement with each application for network service or to
designate a new network resource that attests, for each network
resource identified, that (1) the transmission customer owns or has
committed to purchase the designated network resource and (2) the
designated network resource comports with the requirements for
designated network resources.
909. The Commission stated that network customers should include
this attestation in the customer's comments section of the request when
it confirms the request on OASIS. In the event that a transmission
provider or any other network customer designates a network resource
that it does not own or has not committed to purchase, or that does not
comport with the requirements for designated network resources, the
Commission will deem the network customer to be in violation of the pro
forma OATT and will consider assessing civil penalties on a case-by-
case basis, consistent with the Commission's Policy Statement on
Enforcement. The Commission rejected requests to allow transmission
providers to voluntarily verify terms and conditions of power purchase
agreements, concluding that such authority is unnecessary in light of
the new attestation requirement.
Requests for Rehearing and Clarification
910. South Carolina E&G asks for clarification of the language
describing the attestation requirement in paragraph 1521 of Order No.
890, arguing that it is a less precise paraphrase of the language in
section 30.2 of the pro forma OATT. South Carolina E&G asks the
Commission to confirm that the precise language of section 30.2 governs
and that paragraph 1521 of Order No. 890 does not add any additional
requirements. South Carolina E&G also suggests that, because of space
limitations in the customer's comment section on OASIS, the attestation
can be made by a reference, such as ``the customer attests pursuant to
Section 30.2.''
911. Several petitioners request rehearing of the Commission's
decision to not allow transmission providers to review power supply
contracts for power purchases designated as network resources.\334\
These petitioners argue that allowing such review would improve
reliability and/or allow transmission providers to more accurately
model their systems. Duke and EEI argue that transmission providers
should have the right, but not the obligation, to review such
contracts. They assert that transmission providers have a legitimate
interest in ensuring the reliability of energy service to network loads
on their systems, since interruptions and resulting imbalances may harm
the reliability of the entire system, and because the transmission
providers may be forced to provide backup energy in order to avoid
curtailment of network load. EEI complains that network customers who
incorrectly designate unqualified resources take transmission capacity
that otherwise would be used for transmission service from legitimate
network resources. Duke notes that it has routinely been provided
access upon request to underlying contracts, with commercially
sensitive information redacted.
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\334\ E.g., Duke, EEI, and MISO.
---------------------------------------------------------------------------
912. EEI argues that reliance on attestations by network customers
that their power purchases qualify as network resources is insufficient
to adequately protect against improper designations. EEI states that
some of its transmission provider members have found, by comparing
customer contracts against network resource certifications that are
required by their business practices, that some customers are
incorrectly designating power purchase contracts that clearly do not
meet the Commission's criteria. EEI argues that after-the-fact audits
of customers' attestations do not address the system reliability
concerns of the misuse of the transmission system that results from the
designation of unqualified network resources.
913. EEI acknowledges the Commission's reluctance to place
transmission providers in the position of policing whether customers'
contracts qualify as network resources, but argues that does not
warrant precluding voluntary review of network customers' purchased
power contracts. EEI
[[Page 3095]]
contends that the Standards of Conduct prohibit any transfer of
customer information to the transmission provider's marketing and
energy affiliates and that any residual concerns about transmission
providers deciding whether power purchase contracts qualify as network
resources could be addressed by permitting the transmission provider to
act in a purely advisory role. EEI suggests that transmission providers
could bring concerns about possibly incorrect attestations to the
attention of the customer or, if necessary, the Commission's
Enforcement Hotline. EEI argues that allowing such review by the
transmission provider would not supplant the obligation of the network
customer to attest to the validity of its designations of network
resources.
914. MISO argues that a statement that the transmission customer
owns or has committed to purchase the designated network resource and
that the designated network resource comports with applicable
requirements does not provide the necessary level of assurance to the
transmission provider, particularly in those cases where the network
customer unduly relies on representations made by its supplying
marketers. MISO asks the Commission to supplement its existing
attestation requirements with a certification from an external control
area's administrator and/or the seller of the generation that the
resource being designated in that area is not counted as a designated
network resource for another load on or off the system.
915. Joined by Southern, EEI also objects to making transmission
providers responsible for verifying the firmness of off-system
transmission service. Southern argues that the requirement that
transmission providers verify the firmness of off-system transmission
service is unduly burdensome and could result in unnecessary rejection
of requests to designate network resources on a day-ahead basis.
Southern contends that the specific transmission path(s) and
arrangements to deliver power to the network customer usually have not
been finalized at the time off-system resources are designated in the
``day-ahead'' cycle and, instead, are typically finalized the hour
before delivery. Southern and EEI suggest that sections 29.2(viii),
30.1, 30.2, and 30.7 of the pro forma OATT be amended to allow the
network customer to attest that the external resource is contractually
required to be delivered using firm transmission service, without
confirmation that an actual firm path has been scheduled and confirmed.
Southern argues that transmission customers also could be required to
attest to the firmness of their requested and expected transmission
service and face the possibility of complaint, audit or other inquiry
and, ultimately, sanction for false attestations.
916. In the alternative, EEI requests further clarification that
transmission providers could obtain waiver of the verification
requirement if they demonstrate that verification of the firmness of
transmission service is not required because of the way in which
transmission service and markets operate on the transmission provider's
transmission system. EEI states that network resources in the West are
frequently designated at hubs such as the Palo Verde Hub prior to
tagging. EEI states that a network customer has very limited ability to
know the source of the energy that is being made available at a
specific hub and, indeed, has no need to know that information since
what is important is the seller's commitment that the energy is being
provided at that hub on a firm basis. EEI argues that the host
transmission provider has no ability or need to evaluate the firmness
of the external transmission path between the generator and hub. EEI
contends that the Commission's decision to require verification of the
firmness of transmission paths, in conjunction with other requirements
relating to off-system network resources, has caused financial
institutions to consider withdrawing from the market.
917. EEI and Southern also argue that, in many instances,
transmission providers are unable to perform the verifications required
by the Commission. They state that some systems refuse to allow other
transmission providers access to their OASIS and refuse to perform the
verification themselves. EEI suggests that the Commission require each
transmission provider to grant ``read only'' access to its OASIS by any
computer that has an X509 security certificate (the security
certificate that is provided to transmission function personnel). EEI
requests that the Commission, at a minimum, delay the date by which
transmission providers must verify off-system transmission service for
180 days, in order to allow time for modifications to OASIS protocols
to grant access to transmission providers who are seeking to verify the
firmness of transmission service.
918. If the Commission declines to amend the attestation
requirement, EEI requests clarification with regard to instances where
transmission providers cannot verify the firmness of off-system
transmission service because the information is not posted on OASIS.
EEI states that many non-jurisdictional transmission providers that do
not have reciprocity tariffs also do not have OASIS nodes on which the
firmness of service can be verified. EEI also states that grandfathered
transmission agreements frequently are not posted on OASIS or, if they
are posted, postings do not contain sufficient detail to enable off-
system transmission personnel to verify the firmness of the
transmission service.
Commission Determination
919. The Commission clarifies, in response to South Carolina E&G's
request, that the language in paragraph 1521 of Order No. 890 is only
meant to be a paraphrase of the more detailed attestation to be
provided in the pro forma OATT itself. A network customer designating
network resources should submit an attestation using the language set
forth in sections 29.2(viii) and 30.2 of the pro forma OATT, as amended
in Order No. 890, not the language of the preamble. A network customer
is not permitted to merely reference the applicable section of the pro
forma OATT when completing the attestation requirement. If the OASIS
customer comment section does not currently allow enough space for a
network customer to provide its attestation, transmission providers
should modify, in coordination with NAESB, OASIS functionality to
accommodate the full attestation. In the interim, the transmission
provider should identify alternate means, such as by telefax or e-mail,
for the network customer to provide the attestation.
920. We decline to require that network customers provide their
power supply contracts to transmission providers for review, whether
such review is advisory or otherwise. Allowing transmission providers
to review power sales contracts would put transmission providers in the
position of interpreting their network customer's contracts and
accepting or rejecting designations based on their interpretations.
Regardless of the protections provided by the Standards of Conduct, it
would be inappropriate for transmission providers to be in that
position. The new attestation requirement properly places the
responsibility of interpreting the terms of a power sales agreement on
the network customer, an actual party to the agreement. We believe that
the new attestation requirement, coupled with the prospect of
significant civil penalties for improper attestations, will prove
effective at providing the proper
[[Page 3096]]
incentives for network customers to not designate ineligible network
resources.
921. Similarly, we decline to require, as requested by MISO, that
network customers designating off-system resources provide a
certification from the external control area's administrator and/or the
seller of the generation that the resource being designated is not
counted as a network resource for another load. Again, it is the
responsibility of the network customer to assure that the requirements
of the pro forma OATT are satisfied prior to requesting the designation
of a network resource. The network customer must take appropriate steps
to ensure that the resource has not been committed for sale to non-
designated third party load or is otherwise unable to be called upon to
meet the network customer's network load on a non-interruptible basis.
922. We affirm the decision in Order No. 890 to require each
transmission provider to verify the firmness of off-system transmission
service to deliver designated network resources to the transmission
provider's system. Under normal circumstances, this verification
requirement should not present a significant burden for the
transmission provider because it only requires review of the
transmission arrangements from the designated network resource to the
transmission provider's system. Several of the arguments raised by
petitioners incorrectly assume that the transmission provider is under
an obligation to look beyond a power purchase designated as a network
resource to upstream transmission arrangements from the source
generator. There is no need for the transmission provider to consider
transmission arrangements upstream of the designated resource, since
the network customer has attested that the resource is sufficiently
firm to be designated as a network resource. We therefore do not
believe, as Southern argues, that the verification process will result
in unnecessary rejections of request to designate network resources.
923. We recognize that, in some circumstances, the external
transmission provider may not have an OASIS or make relevant
information on its OASIS available to other transmission providers and,
therefore, the host transmission provider may be unable to use OASIS to
verify the firmness of transmission used to deliver the off-system
designated network resource. The Commission explained in Order No. 890
that the transmission provider should attempt to remedy such
information deficiencies through informal communications with the
customer.\335\ Network customers have every incentive to cooperate in
providing this information since, if the transmission provider is
unable to confirm the firmness of these transmission arrangements, the
request to designate the network resource is deficient. We agree with
EEI and Southern, however, that transmission providers should have
access to view other transmission providers' OASIS for this purpose. We
therefore direct transmission providers to allow such access and to
work through NAESB to modify business practices as necessary.\336\ We
decline to waive the verification requirement in the interim since
transmission providers are able to request this information directly
from customers.
---------------------------------------------------------------------------
\335\ See Order No. 890 at P 1527.
\336\ Transmission providers are free to use the NAESB standards
development process to create automated OASIS functionality for
verifying third-party transmission service at the time a designation
request is submitted or any other processes to further minimize any
burden associated with the verification requirement.
---------------------------------------------------------------------------
c. Undesignation of Network Resources
(1) Risk to ATC Rights
924. The Commission clarified in Order No. 890 that a request for
termination of a network resource that is concurrently paired with a
request to redesignate that resource at a specific point in time will
not result in the network customer permanently forfeiting its rights to
use that resource as a designated network resource. Any change in ATC
that is determined by the transmission provider to have resulted from
the temporary termination shall be posted on OASIS during this
temporary period. A request that is not accompanied with a request to
redesignate that resource at a specific point in time is to be
considered an indefinite termination. After an indefinite termination
of a resource, the network customer has no continuing rights to the use
of such resource and future requests to designate that resource would
be processed consistent with section 30.2 of the pro forma OATT as a
designation of a new network resource.
Requests for Clarification and Rehearing
925. NorthWestern argues that, once upgrades specified through the
interconnection process have been installed, the generator can be
specified as a network resource by any customer, at the time of
commercial operation of the generator or at any time in the future.
NorthWestern acknowledges that the Commission rejected this position in
Order No. 890, but contends that the Commission's determination cannot
be reconciled with the ability of a generator under Order No. 2003 to
designate, during the application process, whether it wishes to be
studied and interconnected as a network resource or an energy
resource.\337\ NorthWestern contends that interconnection as a network
resource assumes that the generator will be eligible to be designated
by any network customer to serve its load in the future. If this is not
the case, NorthWestern questions the distinction between energy
resource interconnection service and network resource interconnection
service and the transmission provider's ability to confidently study
any network generation request will be diminished. NorthWestern states
that a generator's request for network interconnection does not
necessarily mean that any customer has designated the generator as a
network resource, but only that it may be designated as a network
resource by any customer.
---------------------------------------------------------------------------
\337\ Citing Order No. 2003.
---------------------------------------------------------------------------
926. NorthWestern also requests clarification regarding the
interaction of transmission service and generation interconnection
requests, asking the Commission to confirm that both should be studied
through a single queue prioritized by request date. NorthWestern argues
that decoupling the network generation interconnection study from the
transmission service study could undermine reliability. NorthWestern
suggests that all generation interconnection and transmission service
requests be studied through a single study queue, where the requests
are prioritized by their request date, in order to allow the
relationship and mitigation requirements between senior and junior
queued transmission and interconnection requests to be known and
applied appropriately in junior queue studies.
Commission Determination
927. We disagree with NorthWestern that a generator interconnected
under network resource interconnection service (NRIS) may be designated
as a network resource by any customer at any point in time. As the
Commission explained in Order No. 2003-A, NRIS status does not convey
any right to transmit power and does not constitute a reservation of
transmission capacity to any specific point.\338\ The purpose of NRIS
is to provide only those network upgrades needed to allow the aggregate
of generation in the facility's local area to be delivered to the
aggregate of load on the transmission provider's
[[Page 3097]]
transmission system, such that the output of the generating facility
will not be ``bottled up'' during peak load conditions.\339\ As a
result, NRIS does not necessarily provide the interconnection customer
with the capability to physically deliver the output of its generating
facility to any particular load on the system without incurring
congestion costs. Requests for delivery service inside the transmission
provider's transmission system may require additional studies and
upgrades to reduce congestion to acceptable levels.\340\
---------------------------------------------------------------------------
\338\ Order No. 2003-A at P 516.
\339\ Id. at P 531.
\340\ Id. at P 502.
---------------------------------------------------------------------------
928. We decline to adopt at this time NorthWestern's request that
all transmission service and generation interconnection requests be
studied through a single queue prioritized by application date and
time. NorthWestern requests specific revisions to the management of
generator interconnection and transmission service request queues that
were not proposed in the NOPR and are beyond the scope of this
proceeding. Earlier this month, Commission staff held a technical
conference to address issues related to the management of
interconnection queues in Docket No. AD08-2-000.\341\ The queuing
concerns raised by NorthWestern are more appropriately addressed in
that proceeding.
---------------------------------------------------------------------------
\341\ See Interconnection Queuing Practices, Notice of Technical
Conference, Docket No. AD08-2-000 (Nov. 2, 2007); Interconnection
Queuing Practices, Notice Inviting Comments, Docket Nos. AD08-2-000,
et al.
---------------------------------------------------------------------------
(2) Minimum Lead-Time
929. The Commission concluded in Order No. 890 that network
customers should not be permitted to make firm third-party sales from
any designated network resource without (1) undesignating that resource
for the period of the third-party sale pursuant to section 30.3 of the
pro forma OATT and (2) providing notice of such undesignation before
the firm scheduling deadline. The Commission stated that this
requirement allows undesignated capacity to be acquired on a non-firm
basis without creating an undue adverse effect on third-party sales.
Requests for Clarification and Rehearing
930. Various petitioners have requested rehearing or clarification
of the Commission's determinations regarding the minimum lead-time for
undesignating network resources in order to make firm third-party
sales.\342\ Petitioners generally object to imposing this minimum lead-
time requirement, arguing that it unduly restricts the ability of
network customers and the transmission provider to engage in third-
party sales and impairs liquidity in the market.
---------------------------------------------------------------------------
\342\ E.g., APS and EEI, E.ON U.S., Financial Service Joint
Filers, Pacific Northwest Parties, PNM, Progress Energy, Washington
IOUs, and WSPP. In addition, APS and EEI, Barrick Goldstrike Mines,
Bonneville, EPSA, Morgan Stanley, Pacific Northwest IOUs, PNGC
Power, Powerex, PPL Parties, Public Power Council, San Diego G&E,
SCE&G, SoCal Edison, Southern, Southwestern Utilities, and WSPP
filed post-technical conference comments on this issue.
---------------------------------------------------------------------------
Commission Determination
931. In a notice issued on September 7, 2007, the Commission
extended the effective date of the minimum lead-time for undesignating
network resources adopted in Order No. 890, deferring the effectiveness
of the phrase ``* * * but not later than the firm scheduling deadline
for the period of termination'' in section 30.3 of the pro forma
OATT.\343\ The Commission stated that it will address the appropriate
effective date for that tariff language, or any modification thereto,
in a future order to be issued in this proceeding. The Commission
therefore defers responding to the requests for rehearing and
clarification on this subject pending further action in the forthcoming
order.
---------------------------------------------------------------------------
\343\ Preventing Undue Discrimination and Preference in
Transmission Service, Notice Granting Extension of Effective Date,
120 FERC ] 61,222 (2007).
---------------------------------------------------------------------------
(3) General
932. In response to commenter requests, the Commission addressed a
number of other issues in Order No. 890 related to the undesignation of
network resources. Among other things, the Commission denied a request
that network customers be given the flexibility to substitute new
designated network resources without abandoning the original
transmission queue position of the existing designated network
resource. The Commission explained that granting the request would,
without any apparent justification, put point-to-point customers
seeking ATC freed up by an undesignation at a disadvantage. Pending the
implementation of new OASIS functionality to accept electronic requests
to designate and undesignated network resources, the Commission stated
that network customers could submit their requests by transmitting the
required information to the transmission provider by telefax or
providing the information by telephone over the transmission provider's
time recorded telephone line.
933. The Commission clarified that a network customer may only
enter into a third-party power sale from a designated network resource
if the third-party power purchase agreement allows the seller to
interrupt power sales to the third party in order to serve the
designated network load. The Commission stated that such interruptions
must be permitted without penalty, to avoid imposing financial
incentives that compete with the network resource's obligation to serve
its network load. The Commission also clarified that firm third-party
sales may be made from an undesignated portion of a network customer's
network resources (i.e., a ``slice-of-system sale''), so long as all of
the applicable requirements are met. The Commission stated that the
network customer must submit undesignations for each portion of the
resource supporting the third-party sale.
934. The Commission rejected requests to relax rules for changing
the undesignation of network resources at any time to handle system
emergencies, force majeure events, forced outages or unusual weather
conditions. The Commission explained that other procedures such as
those in NERC's standard for Capacity & Energy Emergencies, EOP-002-2,
or the possible use of capacity benefit margin are more appropriate to
deal with legitimate system emergencies. In situations where a request
to undesignate a network resource cannot be accommodated without
jeopardizing reliability, the Commission stated that the transmission
provider could deny the request.
Requests for Rehearing and Clarification
935. Bonneville argues that, if the only ATC on a path is the ATC
freed up by an undesignation, then the network customer should be
granted use of that ATC for its requested alternate service. Bonneville
contends that such a policy would not adversely affect customers
because, if the customer that is undesignating a resource is not placed
first in line for the capacity made available by the undesignation,
that customer would not undesignate (since it will continue to need the
capacity on its existing path) and no capacity would be freed up for
others. Bonneville concludes that refusing to place the undesignating
customer first in line for the freed-up ATC will harm that customer
while advantaging no one. Bonneville suggests that allowing such
redirects of network resources would be particularly helpful for
intermittent resources such as wind, given that transmission customers
with state-
[[Page 3098]]
mandated renewable resource requirements may wish to redirect for a
short-term period to import renewable energy, but may be unable to do
so on a constrained path if they are unable to utilize the capacity
they are freeing up by the request to undesignate.
936. Several petitioners request rehearing or clarification with
respect to the Commission's finding in Order No. 890 that network
customers making firm third-party system sales from network resources
must undesignate each portion of each resource supporting the third-
party sales. \344\ Petitioners generally argue that requiring a network
customer to keep track of the individual generating units and amounts
of generation from each unit being used to supply a system sale is
unduly burdensome or impossible. South Carolina E&G argues that,
between the scheduling deadline and the time when service commences,
any number of events can change the available generating units being
dispatched, change the merit order dispatch, or cause dispatch of
additional units. Joined by EEI, South Carolina E&G asks the Commission
to allow slice of system sales from a generation fleet by undesignating
the amount of the sale.
---------------------------------------------------------------------------
\344\ E.g., Duke, EEI, and South Carolina E&G. Pacific Northwest
IOUs raise similar issues in their post-tech conference comments.
---------------------------------------------------------------------------
937. Duke states that the Commission's policies are clear that for
off-system system sales a generating resource must be identified on a
specific basis for purposes of arranging point-to-point transmission
service to support the off-system sale. However, with regard to
identifying which generating units will be used to generate the energy
to make on-system system sales, Duke argues that the Commission has
never required that particular units or portions of units be identified
and undesignated on a unit-by-unit basis. Duke contends that all
generating units that comprise the ``system'' are used to serve all
loads, and the undesignation process should occur through the
recognition that a share of the generation system is used for retail
native load and a share is used for wholesale native load (i.e.,
requirements customers) and off-system firm load. Duke maintains that
this approach is reasonable and ensures that the transmission provider
is not double-counting or double-reserving transmission capacity needed
to serve such loads, and is purchasing point-to-point service that is
needed.
938. E.ON U.S. argues that the Commission has provided insufficient
protection for LSEs and others that may need to recall undesignated
resources for use to supply native load during times of system
emergencies. E.ON U.S. asks the Commission to make clear in the pro
forma OATT that the obligation to serve native load may require the
redesignation of network resources in times of system emergency. Absent
such a clarification, E.ON U.S. argues that LSEs will be reluctant to
make network resources available to serve the market and, in a time of
emergency, confusion may occur regarding the proper procedure for
redesignating resources.
939. Pacific Northwest IOUs and South Carolina E&G request
clarification in their post-technical conference comments that a
network resource does not have to be undesignated before it is used to
support the provision of reserve energy under a regional reserve
sharing arrangement. E.ON U.S. requests similar clarification, arguing
that flexible undesignation rules are necessary to allow utilities to
quickly respond under reserve-sharing arrangements. Together, they
argue that the failure to provide such clarification, and the related
complications and potential sanctions, could impede or destroy reserve
sharing arrangements and/or seriously imperil system reliability. South
Carolina E&G proposes that the Commission expressly redefine network
load under the pro forma OATT to include responses by the transmission
provider to requests for emergency assistance or calls for reserves
under reserves sharing agreements. If the Commission concludes that the
undesignation requirements apply to designated network load used for
reserve sharing purposes, E.ON U.S. proposes to post on OASIS
information regarding its reserve sharing events within five days of
the end of each month in which an event occurred. E.ON U.S. states that
the particular units used to meet its reserve sharing obligation are
not known until it performs an after-the-fact, monthly allocation of
the highest-cost resources to off-system sales.
940. MidAmerican requests clarification that, during the period
until improved OASIS functionality is available for designating and
undesignating network resources, electronic transmissions and e-mail
are acceptable means of designating and undesignating network
resources. MidAmerican argues that electronic transmittals are similar
to the already accepted telefax and recorded telephone line procedures,
in that they provide a quick, efficient means of communication that can
be readily stored.
941. NRECA requests rehearing of the Commission's determination
that transmission providers have the discretion to deny undesignations
of network resources. NRECA argues that the Commission has given
transmission providers the ability to unduly discriminate against its
wholesale customers (i.e., its direct competitors). Because the
transmission provider is not likely to deny its own undesignation
requests, NRECA contends that comparability requires that it not be
allowed the ability to deny undesignation requests of its network
customers. NRECA argues that while the actual scheduling of a resource
could affect reliability, there should be no reliability effects from
the mere designation or undesignation of a resource. NRECA contends
that there are many other standards and procedures in place to protect
against insufficient capacity.
942. If the Commission retains the ability to deny a request to
terminate the designation of a network resource, NRECA asks the
Commission to at least require that denials come at the direction of
the reliability coordinator, rather than the transmission provider.
NRECA argues that denying the undesignation of a network resource is
akin to designating the resource as a ``must-run'' generating resource.
If the resource is owned by the network customer, NRECA maintains that
the reliability coordinator should be able to designate the unit as a
reliability-must-run unit and compensate the network customer for its
dispatch. If the resource is not owned by the network customer, NRECA
argues that nothing in the FPA authorizes the Commission to require the
network customer or the owner of the resource to continue to contract
for service with each other or use any particular capacity for a
specific purpose.
943. TAPS seeks clarification that a transmission provider could
deny a request to undesignate a network resource only in the context of
requests for temporary undesignation. TAPS argues that there are
circumstances in which a resource is simply not available because, for
example, it is incapable of continued operation or no longer
economically viable or, in the case of a purchase, the contract has
ended.
944. MidAmerican asks that transmission providers be required to
explicitly approve or deny requests to undesignate network resources
and that the timing of action on undesignation requests be made
consistent with the timing requirements to designate a network
resource. MidAmerican argues that clarification is necessary to avoid
confusion when one customer is undesignating a network resource so that
another customer may designate it,
[[Page 3099]]
otherwise a customer could be attempting to designate a resource before
the request to undesignate has been addressed.
945. Bonneville argues that the Commission should not require
network resources to be temporarily undesignated to make firm third-
party power sales if the transmission provider's ATC methodology
already assures that ATC has not been withheld to accommodate the
underlying designation. Bonneville maintains that its transmission
customers usually designate as network resources power purchase
agreements sourced from the resources that comprise the interconnected
hydroelectric system. Bonneville argues that its ATC methodology, which
is based on historical usage data, addresses the Commission's concerns
about the availability of ATC without further requiring network
resources to be undesignated prior to making third-party sales from
those resources.
Commission Determination
946. We disagree with Bonneville's argument that a customer
undesignating a network resource should be first-in-line for the
transmission capacity freed up by such a designation. While it may be
true in some circumstances that a network customer would choose not to
undesignate a resource if there is insufficient ATC to accommodate a
desired alternative transaction, it does not follow that the network
customer's alternative transaction should be put ahead of other
competing requests in the queue. That would undermine long-standing
policies governing the priority of service requests and unduly
preference network customers. The Commission rejects similar requests
by point-to-point customers to be first in line for ATC in section
III.D.4.b.
947. With regard to the undesignation of units used to supply
system sales, we clarify that portions of the seller's individual
network resources supporting a sale of system power do not need to be
undesignated so long as the system sale is itself designated as a
network resource by the buyer. Instead, the seller should undesignate a
portion of its system equal to the amount of the system sale, but which
is not attributed to any specific generators. If the system sale is not
designated as a network resource by the buyer, the seller must submit
undesignations for each portion of each resource supporting the third-
party sale. Since we believe most, if not all, system sales sourced
from designated network resources are themselves designated as network
resources by the buyer, we expect that few system sales will require
undesignation on a unit-by-unit basis.
948. As we reiterate in section III.D.9.c there is also no need to
undesignate network resources prior to making sales that permit
curtailment without penalty to serve the seller's native load.\345\
Since there is no need to undesignate resources to make such sales,
there is no corresponding need to redesignate those resources in times
of emergency when power is recalled to serve native load. We therefore
disagree with E.ON U.S. that special redesignation procedures are
necessary for LSEs selling recallable energy. In response to Pacific
Northwest IOUs and South Carolina E&G, we amend sections 1.26 and 30.4
of the pro forma OATT to make clear that network resources do not have
to be undesignated before they are used to support the provision of
reserve energy under a Commission-approved reserve sharing agreement.
---------------------------------------------------------------------------
\345\ See Order No. 890 at P 1459; see also WPPI 84 FERC at
61,152. Curtailment contemplates a reduction in service as a result
of system reliability conditions, not economic reasons.
---------------------------------------------------------------------------
949. In response to MidAmerican's request, we clarify that, pending
implementation of the new OASIS functionality, submission of requests
to designate and undesignate network resources may be provided by any
appropriate electronic procedures established by the transmission
provider, or by telephone or telefax as provided in Order No. 890.
950. We grant NRECA and TAPS' request for rehearing of the
Commission's decision in Order No. 890 to allow transmission providers
to deny requests to terminate network resource designations in certain
situations. Upon consideration of petitioners' arguments, we agree that
it is not appropriate to allow the transmission provider to deny
undesignation, effectively requiring the network customer to continue
to make available a resource that the customer is unable to, or no
longer wishes to, make available. Reliability problems caused by the
lack of available resources should be dealt with through other means,
such as negotiation of must-run service agreements. In light of this
decision, MidAmerican's request to establish a time by which a
transmission provider must act on a request to terminate the
designation of a network resource is rejected as moot.
951. We disagree with Bonneville that the pro forma OATT should be
amended to allow for firm third-party sales from a network resource
without first undesignating the network resource. If the particular ATC
methodology used by the transmission provider allows for flexibility in
implementing this requirement, the transmission provider may propose a
variation to the pro forma OATT in an FPA section 205 filing. Any such
request should adequately address the Commission's concern, as stated
in Order No. 888, that network customers may (absent a prohibition on
network resources including any portion of a resource that was
committed for sale to a third party) have the incentive to specify
unlimited generation resources to be integrated into their load without
any commensurate financial obligation, given that network transmission
service is billed on a load ratio basis.\346\
---------------------------------------------------------------------------
\346\ See Order No. 888 at 31,753-54.
---------------------------------------------------------------------------
6. Clarifications Related to Network Service
a. Secondary Network Service
952. In Order No. 890, the Commission declined to adopt further
limitations to the use of secondary network service under section 28.4
of the pro forma OATT, which allows a network customer to deliver
energy to its network load from non-designated network resources on an
as-available basis without additional charge. Although the Commission
had proposed in the NOPR to limit the proper use of secondary network
service to deliveries of economy energy only, upon review of comments
submitted on this issue the Commission concluded that there were
instances outside of the proposed definition of economy energy that
warranted the use of secondary network service. The Commission
therefore decided to retain the existing section 28.4 of the pro forma
OATT that allows the use of secondary network service ``to deliver
energy to its Network Loads.''
Requests for Rehearing and Clarification
953. Idaho Power asks the Commission to clarify the showing that
transmission customers must make to demonstrate that they are using
secondary network service properly or not using secondary network
service to support off-system sales. Idaho Power states that several
commenters lamented in response to the NOPR the difficulties of making
the calculations necessary to demonstrate that secondary network
service is not being used to support off-system sales. Idaho Power
contends that the Commission has never clearly articulated the test
used to determine improper use of network service. Although Idaho Power
acknowledges that the Commission has provided some guidance on these
issues in audit and investigation reports, Idaho Power states
[[Page 3100]]
that it is unclear to what extent the Commission intends language in
such reports to apply beyond the context of the particular audit or
investigation.
954. Idaho Power suggests that an economic test would not be
precise enough to address all the circumstances where network and
secondary transmission should be used. Idaho Power asks that the
Commission instead consider three factual questions to evaluate the
proper use of secondary network service: Whether the utility's
decisions were intended to maintain a balanced portfolio for service to
load; whether the off-system sale was made at a time when the utility's
resources exceeded its expected load and needed to balance its
portfolio; and, whether the utility either actually needed the imported
energy to serve load or needed the imported energy to replace a more
expensive resource that otherwise would have been used to serve load.
If the answer to these questions is ``yes,'' then Idaho Power argues
that the use of network or secondary transmission should always be
allowed to import energy.
955. Idaho Power also asks the Commission to articulate the types
of records it expects a utility to maintain in order to document the
use of its transmission network in compliance with Commission
requirements. In Idaho Power's view, clarification of the rules and
corresponding documentation requirements will allow utilities and other
network customers to become more comfortable using secondary network
service rather than buying excessive amounts of point-to-point
transmission.
Commission Determination
956. The Commission affirms the decision in Order No. 890 to retain
the existing test for eligibility to use secondary network service,
i.e., when energy is delivered to serve network loads. In rejecting the
proposed restriction to deliveries of economy energy, the Commission
recognized that there may be instances that warrant the use of
secondary service in order to serve network loads reliably that would
not satisfy an economic test, as Idaho Power suggests. The Commission
declined to adopt other restrictions on the use of secondary network
service proposed by commenters, expressing concern that the proposals
could preclude legitimate use of secondary network service.
957. We similarly conclude that the alternative three-part factual
test proposed by Idaho Power might not reflect all of the factors to be
considered in determining whether a particular use of secondary network
service was to deliver energy to network loads. The Commission did not
preclude in Order No. 890 consideration of whether the delivery in
question is economic energy and, instead, determined that restricting
the use of secondary network service only to economic energy would be
too severe. The primary focus of the Commission's analysis is whether
the energy delivered using secondary network service was intended to
serve network load. Whether a delivery in question is for economic
energy may very well be relevant when considering intent, but so would
contemporaneous documentation and other evidence. We will continue to
address the appropriate use of secondary network service on a case-by-
case basis, as in MidAmerican,\347\ which we intend to serve as
guidance to the industry regarding the appropriate use of secondary
network service and the documentation that would be relevant for
analysis.
---------------------------------------------------------------------------
\347\ MidAmerican Energy Co., 112 FERC ] 61,346 at P 6 (2005)
(MidAmerican).
---------------------------------------------------------------------------
b. ``On an as-available basis''
958. The Commission clarified in Order No. 890 that secondary
service must be requested in accordance with section 18, including the
timing restrictions set forth in section 18.3 of the pro forma OATT.
The Commission explained that secondary service is on an as-available
basis and that network customers should not be allowed to lock in such
service in advance of other non-firm uses of available transmission.
The Commission concluded that allowing lower priority secondary service
to have a scheduling advantage over non-firm transmission would be
inappropriate and would discourage the use of non-firm transmission
service.
Requests for Rehearing and Clarification
959. Several petitioners request clarification regarding the
priority level of secondary network service in relation to non-firm
transmission service. NRECA, Southern, and TDU Systems ask the
Commission to clarify that secondary service has a higher priority than
non-firm point-to-point service. These petitioners state that section
28.4 of the pro forma OATT grants secondary service a higher priority
than all non-firm point-to-point service and that the Commission's
reference to secondary network service as ``lower-priority'' in Order
No. 890 is incorrect and contradictory of Order No. 888. Without a
higher priority for secondary network service, these petitioners
contend that network customers located in constrained regions who are
forced to rely on secondary service will be worse off and reliability
will be impaired.
960. Joined by TAPS, NRECA argues that application of the
scheduling requirements for non-firm point-to-point service to network
customer reservations of secondary service would present a serious set-
back for LSEs. NRECA states that its members commonly use secondary
service to import long-term firm power from other states into their
home states in order to serve native load. NRECA argues that this use
of secondary service could not happen if network customers were held to
the timing restrictions in section 18.3. NRECA contends that precluding
network customers from acquiring secondary service to coincide with
long-term generation requirements, but before actual use of the
transmission, would contradict Congressional intent to preserve and
enhance network service to native load.
961. NRECA further contends that there is no evidentiary record for
finding that the existing practice of scheduling secondary service
without regard to the time restrictions of section 18.3 has
``discouraged'' the use of non-firm transmission service or minimized
associated revenue credits. Even if that is the case, NRECA argues that
secondary network service customers should have priority and any
marginal amount of foregone revenues is justified by more reliable,
economic service for LSEs. Because network customers pay a load ratio
share of total transmission costs regardless of whether their energy is
coming from designated network resources or non-designated network
resources on an as-available basis, NRECA concludes that network
customers use the transmission system in a fundamentally different way
from non-firm users and, therefore, they should not be held to the same
timing restrictions in 18.3 that apply to non-firm customers.
962. TAPS argues that, as long as network customers bear a full
share of the costs of operating the entire system, they should have
first call on non-firm use, just as secondary network service is the
last non-firm use to be curtailed in response to constraints. In the
event the Commission denies rehearing on this issue and retains the new
timing restrictions on secondary service, TAPS asks that transmission
providers also be required to abide by those same requirements when
they seek to use an undesignated resource (or the undesignated portion
of a resource) to service their native load.
[[Page 3101]]
Commission Determination
963. The Commission grants clarification of the reference to
``lower-priority'' secondary network service in paragraph 1606 of Order
No. 890, which was intended to distinguish secondary network service
from firm transmission service, not non-firm transmission service.
Section 28.4 of the pro forma OATT affords secondary service a higher
curtailment priority than any non-firm point-to-point service and the
Commission did not intend to imply otherwise in Order No. 890. We
disagree, however, that secondary service should be allowed a higher
scheduling priority compared to all other non-firm service. Secondary
service is on an ``as available'' basis and, therefore, network
customers should not be allowed to lock in such service in advance of
other non-firm uses of available transmission.
964. Petitioners' arguments to the contrary are misplaced. Although
FPA section 217 does address LSE uses of the transmission systems, the
focus of that provision is on the use of firm transmission, not non-
firm uses such as secondary network service. The fact that network
customers pay a load ratio share of transmission costs does not grant
them superior rights when scheduling firm transmission, nor should it
justify superior rights when scheduling uses of the transmission system
other than firm uses. Any request for secondary network service
therefore must be made in compliance with section 18, including the
timing restrictions set forth in 18.3, of the pro forma OATT. In
response to TAPS, we reiterate that section 28.2 of the pro forma OATT
requires the transmission provider to designate resources and loads in
the same manner as any network customer.
c. Behind the Meter Generation and Uses of Point-To-Point Service
965. The Commission declined to require transmission providers to
allow netting of behind the meter generation against transmission
service charges to the extent customers do not rely on the transmission
system to meet their energy needs, stating that commenters had not
provided any different arguments not fully addressed in Order No. 888.
The Commission explained that the existing pro forma OATT already
allowed transmission customers to exclude the entirety of a discrete
load from network service and serve such load with the customer's
behind the meter generation and point-to-point transmission service as
necessary, thereby reducing the network customer's load ratio share.
The Commission concluded it is most appropriate to continue to review
alternative transmission provider proposals for behind the meter
generation treatment on a case-by-case basis.
Requests for Rehearing and Clarification
966. Washington IOUs contend that the language added to section
30.4 of the pro forma OATT in Order No. 890 appears to permit a
transmission provider or network customer to take point-to-point
service to deliver power from remote network resources to loads in
certain instances. Washington IOUs ask the Commission to clarify that a
transmission provider or network customer may use short-term firm
point-to-point service to serve native load or network load,
respectively. Washington IOUs state that there are at least two events
in which the use of point-to-point service to serve native or network
load is needed and appropriate: the need to import power when it is
unclear whether or not the power will be deemed to be used to serve
native or network load because of its relative cost; and the need to
import power reliably from non-designated network resources in order to
serve native or network load, instead of relying on secondary network
service. In their view, a restriction on the use of point-to-point
service would prevent the transmission provider and network customer
from competing for scarce transmission capacity in order to serve their
native or network load.
967. Idaho Power similarly asks the Commission to clarify whether a
network customer or transmission provider could use point-to-point
transmission to serve load in addition to, and not in place of, paying
its full load ratio share for use of the network. Idaho Power contends
that a transmission provider or network customer should have the option
to compete in the market for point-to-point service when it is not sure
at the time of a purchase whether the energy will be needed for load or
sold off-system as surplus, provided they pay the full value of point-
to-point service. Alternatively, Idaho Power requests the Commission
clarify that the network customer and the transmission provider may
procure firm point-to-point service in order to serve native and
network load when the utility requires capacity in addition to the
existing network reservations or secondary transmission over an
interface. In order to ensure that network and secondary transmission
rights are not being used to support off-system sales, Idaho Power
contends that the use of network transmission rights must be minimized
and used in combination with point-to-point service.
968. Idaho Power also requests clarification that the following
examples are considered proper uses of network transmission, secondary
transmission and point-to-point transmission. First, use of point-to-
point transmission to accomplish an off-system sale entered into at a
time the utility was forecasted to be long, even if followed by a
subsequent purchase to serve load using secondary network service or
point-to-point transmission if the utility becomes short. Second, use
of a combination of network service, secondary network service, or
point-to-point transmission for a purchase at a time the utility was
forecasted to be short, even if followed by a subsequent sale using
point-to-point transmission from a portion of that resource that
becomes excess due to a drop in forecasted load. Third, and related,
use of network transmission for a purchase expected to serve load, even
if followed by a subsequent sale using point-to-point service from a
portion of that resource that becomes excess in real-time. Fourth, use
of point-to-point service to purchase economic energy to serve network
load in conjunction with an off-setting undesignation of network
resources and sale of energy off system using point-to-point
transmission. Finally, use of secondary network service to purchase
economic energy to serve network load in conjunction with an off-
setting undesignation of network resources and sale of energy off
system using point-to-point transmission. Idaho Power contends that
only the last example should involve an economic test to demonstrate
that the imported resource will displace a resource in the utility's
load service stack of resources.
969. TAPS and FMPA argue that the Commission failed to consider in
Order No. 890 the circumstance when it is physically impossible for the
transmission system to actually deliver a customer's full load, which
they contend was not addressed in Order No. 888.\348\ TAPS states that
the Commission's proposed solution of the exclusion of the entirety of
a discrete load from network service is no help to a customer that is
served through a single delivery point and, therefore, has no discrete
load that could be service through a combination of point-to-point
service and behind the meter generation while other load takes network
service. FMPA argues that it is unjust to charge a customer for service
that cannot be provided and, therefore, there should be an exception to
load ratio share pricing
[[Page 3102]]
when the transmission provider is unable to serve the network
customer's entire load.
---------------------------------------------------------------------------
\348\ Citing Florida Mun. Power Agency v. FERC, 411 F.3d 287,
291 (D.C. Cir. 2005).
---------------------------------------------------------------------------
Commission Determination
970. As stated in Order No. 890, the pro forma OATT permits
transmission customers to exclude the entirety of a discrete load from
network service and serve such load with the customer's behind the
meter generation and through any needed point-to-point transmission
service, thereby reducing the network customer's load ratio share.\349\
In other situations, use of point-to-point service by network customers
is in addition to network service and therefore does not serve to
reduce their load ratio share. As the Commission concluded in Order No.
888-A, transmission customers ultimately must evaluate the financial
advantages and risks and choose to use either network integration or
firm point-to-point transmission service to serve load.\350\ Any
alternative transmission provider proposals for behind the meter
generation treatment will be reviewed on a case-by-case basis.\351\
---------------------------------------------------------------------------
\349\ See Order No. 890 at P 1619.
\350\ Order No. 888-A at 30,260-61.
\351\ See, e.g., PJM Interconnection, L.L.C., 113 FERC ] 61,279
(2005).
---------------------------------------------------------------------------
971. With regard to concerns of insufficient transmission to serve
the network customer's full load, we fail to understand how, under
normal circumstances, the transmission provider has no capacity to
service a load that has been designated by the network customer. Once a
load has been designated, it is the obligation of the transmission
provider to serve that load and to plan its system so that the load can
be accommodated in the future. To assist the transmission provider in
fulfilling that obligation, network customers are required to provide
load forecasts to the transmission provider each year. The transmission
planning reforms adopted in Order No. 890 will add greater transparency
to this planning process, better enabling network customers to
understand how their needs are reflected in the development of the
transmission system. To the extent a transmission provider is unable to
satisfy its obligation to serve a designated network load, it is more
appropriate to address that situation on a case-by-case basis.
972. The Commission also declines to address here the hypothetical
scenarios offered by Idaho Power. Any determination regarding the
appropriate use of secondary, network, or point-to-point service will
depend upon the facts surrounding the use of such services. While load
forecasts may change and weather related incidents may occur, with
corresponding implications for a utility's purchasing activities, it is
most appropriate for the Commission to consider whether a particular
transaction is an appropriate use of secondary network service based on
the facts and circumstances surrounding the transaction, as discussed
above.
7. Transmission Curtailments
973. The Commission did not propose in the NOPR, or adopt in Order
No. 890, any changes to the terms and conditions under which a
transmission provider may curtail service to maintain reliable
operation of the grid, as set forth in sections 13.6 and 14.7 for
point-to-point service and section 33 for network service. The
Commission did, however, conclude that the posting of additional
curtailment information is necessary to provide transparency and allow
customers to determine whether they have been treated in the same
manner as other transmission system users, including customers of the
transmission provider. Accordingly, the Commission required
transmission providers, working through NAESB, to develop a detailed
template for the posting of additional information on OASIS regarding
firm transmission curtailments, including all circumstances and events
contributing to the need for a firm service curtailment, specific
services and customers curtailed (including the transmission provider's
own retail loads), and the duration of the curtailment.
Requests for Rehearing and Clarification
974. Powerex claims the Commission improperly rejected its request
that the pro forma curtailment provisions be modified to provide for
pro rata curtailment based on a customer's reserved capacity rather
than its scheduled capacity. Powerex states that the Commission appears
to have misunderstood its proposed two-stage curtailment procedure,
which was rejected for having the potential to impair reliability since
the amount of capacity curtailed using that approach would not address
the actual power flows and, therefore, could be less than required to
relieve the overloaded facility. Powerex explains that the proposed
two-stage process pertained solely to the timeframe before power is
actually flowing. Powerex further states that pro rata curtailments
based on reservation capacity would be made prior to the energy
scheduling and tagging deadline (e.g., 20 minutes before the operating
hour), that the transmission provider would compare a customer's
individual schedule to its reduced/curtailed rights, and, if the
customer's scheduled quantities fall within its reduced rights, that
schedule would flow uncut. After calculating the total capacity
scheduled following the application of the pro rata curtailment,
Powerex proposes that any excess transmission be allocated back on a
pro rata basis to transmission customers whose schedules were cut below
their reduced rights. Powerex states that this would in no way affect
curtailments to actual power flows. Powerex suggests that curtailment
within the hour, due to the limited time available to affect relief,
should continue to be allocated based on actual schedules.
975. Powerex contends that the Commission mistakenly concluded that
Powerex's proposal would adversely impact reliability, arguing that the
amount of capacity curtailed under the two-stage process would be no
different from the amount of capacity the transmission provider
believes is necessary to address the constraint and that the capacity
would be more equitably and economically cut according to the
transmission customers' reserved quantities rather than the scheduled
quantities. Powerex states that it is not aware of a single commenter
that provided any evidence that the above modification would be
detrimental in any way to reliability, nor did the Commission provide
any evidentiary support for its response.
976. E.ON U.S. requests clarification of the correct order of
curtailments given the addition of conditional firm point-to-point
transmission service. Specifically, E.ON U.S. requests clarification
regarding the curtailment priority of the different conditional firm
options, i.e., conditions based on an annual number of hours and
conditions based on specific system conditions.
Commission Determination
977. The Commission rejects Powerex's request to modify the
curtailment provisions of the pro forma OATT to provide for pro rata
curtailment based on a customer's reserved capacity rather than its
scheduled capacity. Although Powerex addresses in its request for
rehearing the Commission's initial concern regarding the proposal,\352\
we continue to believe that the proposal would have a potentially
adverse impact on reliability. Powerex's proposal would
[[Page 3103]]
greatly increase the complexity of scheduling transactions at or near
real-time operations, threatening reliability without providing
significant competitive benefits. Powerex has taken a complex issue and
presented it in two simple steps, leaving out the details of how the
transmission operators could obtain all the necessary information
required to make on-the-spot decisions, perform the analyses to
determine whether each schedule flow fully utilizes its respective
reservation, reallocate unused reserved capacity, and curtail
transactions without impairing reliability. We thus reject the
Powerex's request for rehearing in this regard.
---------------------------------------------------------------------------
\352\ See Order No. 890 at P 1629 (stating that the amount of
capacity actually curtailed under the Powerex proposal might be less
than required to relieve the overloaded facility).
---------------------------------------------------------------------------
978. In response to E.ON U.S., we reiterate that the Commission
adopted a secondary network curtailment priority to apply for the hours
or specific conditions when conditional firm service is conditional.
During non-conditional periods, conditional firm service curtailment is
treated consistent with curtailment of other long-term firm
service.\353\ We reiterate that Order No. 890 did not change the terms
and conditions under which a transmission provider may curtail service
to maintain reliable operation of the grid or change the priority of
curtailment for any type of transmission service. Rather, conditional
firm point-to-point service, as adopted in Order No. 890, fits within
the existing curtailment priorities and constructs.
---------------------------------------------------------------------------
\353\ See id. at P 1074.
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8. Standardization of Rules and Practices
a. Business Practices
979. In Order No. 890, the Commission adopted the NOPR proposal to
continue to require that only those rules, standards, and practices
that significantly affect transmission service be incorporated into a
transmission provider's OATT. The Commission affirmed the use of a
``rule of reason'' to determine what rules, standards, and practices
significantly affect transmission service and, as a result, must be
included in the transmission provider's OATT.
980. Regarding rules, standards, and practices that relate to
transmission service, but are not included in the OATT, the Commission
required transmission providers to post this information on their
public Web sites and make it accessible via OASIS. The Commission made
this requirement applicable to all such rules, standards, and
practices, currently written or otherwise.\354\ The Commission stated
that it would not be appropriate to place the rules, standards, and
practices only on OASIS, as some transmission providers use
certificates to restrict access to their OASIS sites. The Commission
amended section 4 of the pro forma OATT to establish this posting
requirement.
---------------------------------------------------------------------------
\354\ With respect to the business practices developed by NAESB,
the Commission noted that there may be copyright restrictions that
limit the transmission provider's ability to post those practices on
its own Web site. In such instances, the Commission stated its
expectation that the transmission provider will reference any NAESB
practices it uses and provide a link on its public Web site to the
copyrighted material on the NAESB Web site.
---------------------------------------------------------------------------
981. The Commission also required each transmission provider to
post on its public Web site, with a corresponding link on OASIS, a
statement of the process by which the transmission provider will amend
the rules, standards, and practices that relate to transmission
service, but which are not included in the OATT. The Commission stated
that this process must include a mechanism to provide reasonable notice
of any proposed changes to a posted business practice and the
respective effective date of such change.\355\ Section 4 of the pro
forma OATT was further amended to formalize this posting requirement.
---------------------------------------------------------------------------
\355\ The Commission permitted transmission providers to adopt
such additional procedures they deem appropriate, such as
opportunities for comment to proposed changes to rules, standards,
and practices.
---------------------------------------------------------------------------
982. Finally, the Commission adopted the NOPR proposal to amend the
pro forma OATT by including a new Attachment L specifying the
qualitative and quantitative criteria that the transmission provider
uses to determine the level of secured and unsecured credit required.
The Commission determined that Attachment L must contain the following
elements: (1) A summary of the procedure for determining the level of
secured and unsecured credit; (2) a list of the acceptable types of
collateral/security; (3) a procedure for providing customers with
reasonable notice of changes in credit levels and collateral
requirements; (4) a procedure for providing customers, upon request, a
written explanation for any change in credit levels or collateral
requirements; (5) a reasonable opportunity to contest determinations of
credit levels or collateral requirements; and (6) a reasonable
opportunity to post additional collateral, including curing any non-
creditworthy determination. The Commission stated that the transmission
provider could supplement Attachment L with a credit guide or manual to
be posted on OASIS.
Requests for Rehearing and Clarification
983. TDU Systems contend that the Commission's filing standard
suggests that the ``rule of reason'' test will only come into play
after it has determined that a particular practice is one that
significantly affects transmission service. TDU Systems argue that,
once the Commission has determined that a practice significantly
affects rates and services, the only remaining question is whether the
practice is realistically susceptible of specification and is not so
generally understood in any contract or arrangement as to render
recitation superfluous.\356\ TDU Systems contend that Order No. 890 is
an unexplained departure from prior precedent and that the Commission
failed to justify its limitation on the data to be included in the
OATT.
---------------------------------------------------------------------------
\356\ Citing City of Cleveland v. FERC, 773 F.2d 1368, 1376
(D.C. Cir. 1985) (City of Cleveland).
---------------------------------------------------------------------------
984. In order to increase certainty, TDU Systems also requests that
the Commission specify in advance the different categories of
transmission provider issuances that the Commission expects to see in
the tariffs. At a minimum, TDU Systems asks that the Commission clarify
that any rule, standard, or practice that can serve to limit a
transmission customer's access to transmission service is one that
significantly affects transmission service and, therefore, should be
included in the OATT.
985. Old Dominion requests that the Commission clarify that, for
individual transmission-owning members of an RTO that do not maintain
their own OATT, the transmission owners must comply with the
requirements of Order No. 890 by including in the RTO's OATT any rules,
standards and practices that affect transmission service that are
either different from or an expansion upon those in the RTO's OATT. Old
Dominion states that this is necessary because individual transmission
owners' planning criteria and business practices can limit access to
transmission service in the same manner as those of the RTO.
986. NRECA states that it supports the Commission's decision to
require each transmission provider to post on its public Web site (with
a corresponding link on OASIS) all rules, standards or business
practices that relate to the terms and conditions of transmission
service, if not already stated in the OATT itself. NRECA contends,
however, that the Commission's subsequent discussion of transmission
providers' credit guides or manuals seemingly allows that information
to be
[[Page 3104]]
posted only on OASIS.\357\ Because credit is such an important
potential barrier to transmission access, NRECA maintains that it is
critical for the details of the credit criteria and methodologies to be
posted on the public Web site of the transmission provider, with a link
on OASIS. NRECA also contends that a statement should be added to the
first paragraph of Attachment L explicitly clarifying that the credit
review procedures and criteria may not unfairly disadvantage public
power entities or other customer groups having unconventional financing
or business structures.
---------------------------------------------------------------------------
\357\ Citing Order No. 890 at P 1657-58.
---------------------------------------------------------------------------
987. Southern requests that the Commission grant rehearing to allow
a transmission provider that does not restrict access to its OASIS site
the option of posting rules, standards and practices relating to
transmission service on its OASIS with a link to such information on
its public Web site. Southern maintains that permitting transmission
providers that do not restrict access to their OASIS to make required
postings on OASIS would satisfy the Commission's objective to provide
public access to such information. Southern argues that not allowing
such flexibility would be arbitrary and capricious.
Commission Determination
988. The Commission did not intend, as TDU Systems suggest, that
the Commission must first determine that a particular practice
significantly affects transmission service before it applies the ``rule
of reason.'' In Order No. 890, the Commission ``affirm[ed] the use of a
``rule of reason'' to determine what rules, standards, and practices
significantly affect transmission service and, as a result, must be
included in the transmission provider's OATT.'' \358\ Specifically, the
``rule of reason'' requires ``recitation of only those practices that
affect rates and services significantly, that are realistically
susceptible of specification, and that are not so generally understood
as to render recitation superfluous.'' \359\ The Commission intends to
continue to use the ``rule of reason'' for this purpose, consistent
with its statutory responsibility and precedent.
---------------------------------------------------------------------------
\358\ Id. at P 1649.
\359\ Public Serv. Co. of Colo., 67 FERC ] 61,371 at 62,267
(1994) (quoting City of Cleveland, 773 F.2d at 1376).
---------------------------------------------------------------------------
989. We decline to specify in advance the particular categories of
rules, standards, and practices that must be documented in the
transmission provider's OATT. Although rules, standards, and practices
that limit a transmission customer's access to transmission service may
very well have a significant effect on transmission services, and
therefore should be in the OATT, any attempt to list the specific
categories of rules, practices and standards that must be included in
an OATT would be over- or under-inclusive as applied to a particular
transmission provider. The Commission believes that, through
application of the ``rule of reason,'' we will be better able to
identify those rules, standards and practices that significantly affect
transmission service and, as a result, are required to be in each
transmission provider's OATT.
990. In response to Old Dominion, we reiterate that each ISO and
RTO must include in its OATT all of the rules, standards and practices
that significantly affect the transmission service provided by the ISO
or RTO and must electronically post all of the rules, standards and
practices that relate to transmission service, but which are not
included in the OATT. To the extent any of the transmission-owning
members of the ISO or RTO have additional rules, standards and
practices that significantly affect, or relate to, the transmission
service being provided by the ISO or RTO, the ISO or RTO must include
such rules, standards and practices in its OATT or electronic postings,
as relevant. Transmission customers must be able to understand the
rules, standards and practices that affect or relate to the service
being provided by the transmission provider, even if such rules,
standards or practices are developed or implemented by third parties.
991. We agree with Southern's request for rehearing to allow a
transmission provider that does not restrict access to its OASIS site
the option of posting rules, standards and practices relating to
transmission service on its OASIS with a link to such information on
its public Web site. The Commission is sympathetic to Southern's
concern and agrees that section 4 of the pro forma OATT, as revised by
Order No. 890, is overly restrictive. The Commission's purpose in
revising section 4 was to ensure that the public has unrestricted
electronic access to the transmission provider's rules, standards and
practices that are not included in its OATT. The Commission concludes
that the transmission provider should be free to place this information
on OASIS, its public Web site or other suitable electronic platform as
long as the transmission provider provides, both on OASIS and on its
public Web site, an electronic link to the information. We have revised
section 4 accordingly.
992. We also agree with NRECA that, in Order No. 890, the
Commission appears to allow the transmission provider to post its
credit guides or manuals only on OASIS.\360\ This was not our intent.
The Commission considers credit guides and manuals containing more
detailed information than that required in Attachment L to be rules,
standards or practices that relate to transmission service, that not be
included in the transmission provider's OATT. We clarify that the
transmission provider must electronically post such credit guides and
manuals and provide a link to that information on its public Web site
and OASIS. We deny as unnecessary NRECA's request to add a statement to
Attachment L regarding application of credit review procedures and
criteria to customer groups with unconventional financing or business
structures. The Commission already provided in Order No. 890 that
transmission providers must consider both quantitative and qualitative
factors so that the particular circumstances surrounding public power
entities can be recognized when analyzing their creditworthiness.\361\
---------------------------------------------------------------------------
\360\ See Order No. 890 at P 1657-58.
\361\ See id. at P 1659.
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b. Limitation on Liability
993. In Order No. 890, the Commission declined to amend the
liability protections found in the pro forma OATT for the same reasons
that the Commission rejected similar proposals in the past.\362\ The
Commission relied upon the reasoning found in Order Nos. 888-A, 888-B,
2003,\363\ the Reliability Policy Statement,\364\ and Commission
precedent.\365\ The Commission explained that the pro forma OATT was
not intended to address liability issues and that liability was a
separate issue from indemnification.\366\ The Commission further
explained that
[[Page 3105]]
transmission providers were not precluded from relying on state laws
that protected utilities or others from claims founded in ordinary
negligence.\367\ The Commission declined to adopt a uniform federal
liability standard and decided that, while it was appropriate to
protect the transmission provider through force majeure and
indemnification provisions from damages or liability when service is
provided by the transmission provider without negligence, it would
leave the determination of liability in other instances to other
proceedings.\368\
---------------------------------------------------------------------------
\362\ See, e.g., Southwest Power Pool, Inc., 113 FERC ] 61,287
(2005); Southern Company Services, Inc., 113 FERC ] 61,239 (2005);
Nevada Power Co., 99 FERC ] 61,347 (2002); Arkansas Louisiana Gas
Co. v. Hall, 7 FERC ] 61,175, reh'g denied, 8 FERC ] 61,039 (1979).
\363\ Order No. 2003 at P 636; Order No. 2003-A at 31,162.
\364\ Policy Statement on Matters Related to Bulk Power System
Reliability, 107 FERC ] 61,052 (2004) (Reliability Policy
Statement).
\365\ See, e.g., Northeast Utilities Services Co., 111 FERC ]
61,333 (2005) (Northeast Utilities); Southwest Power Pool, Inc., 112
FERC ] 61,100 at P 39 (2005); Southern Company Services, Inc., 113
FERC ] 61,239, at P 7 (2005).
\366\ See Order No. 888-A at 30,301 and Order No. 888-B at
62,081 (section 10.2 of the pro forma OATT).
\367\ Order No. 888-A at 30,301.
\368\ Order No. 888-B at 62,081.
---------------------------------------------------------------------------
Requests for Rehearing and Clarification
994. Washington IOUs request that the Commission grant rehearing
and establish a uniform liability provision in the pro forma OATT that
limits transmission provider liability except in instances of gross
negligence or willful misconduct. In their view, enactment of mandatory
reliability standards under FPA section 215, the threat of civil
penalties and other remedial actions, and state oversight all provide
appropriate incentives for utilities to exercise due care in the
operation of their systems. Washington IOUs argue that state
protections do not appear to be sufficient to protect a transmission
provider against outage liability since they have arisen in the context
of claims by retail customers. They argue that granting liability
limitations except in instances of gross negligence or intentional
misconduct is appropriate given that outage liability is not necessary
to ensure utilities operate their transmission systems reliably.
995. Washington IOUs also contend that limitations of liability can
be effected by contracts, such as the pro forma OATT, under much state
law. They argue that it is therefore arbitrary for the Commission to
expect transmission providers to rely on state law for appropriate
limitations of liability, while preventing the inclusion of provisions
in the pro forma OATT to effectuate such limitations of liability.
Washington IOUs also argue that the Commission has provided no good
reason for approving limitations on liability for RTOs/ISOs, but not
for other transmission providers. In their view, the policy concerns
justifying liability limitations for utilities in RTOs/ISOs are
identical to those confronting utilities in non-RTO/ISO areas.
Commission Determination
996. The Commission denies rehearing of the determination in Order
No. 890 not to change the liability protections found in the pro forma
OAAT. Washington IOUs raise no new arguments in support of their
position. As the Commission explained in Order No. 890, proposals by
public utilities to amend their OATTs to include limitations on
liability will be considered on a case-by-case basis.\369\ On review of
such requests, the Commission will consider whether state laws provide
inadequate protection from liability.\370\ In response, Washington IOUs
argue that state law protections appear to be insufficient because they
arose in the context of claims by retail customers, yet petitioners
offer no evidence that transmission providers are in fact precluded
from relying on state law for liability protections. The potential for
legal and regulatory gap is therefore not so great as to warrant
inclusion of liability protections in the pro forma OATT for all
transmission providers.
---------------------------------------------------------------------------
\369\ See Order No. 890 at P 1675 (citing Reliability Policy
Statement at P 40).
\370\ See Southern Company Services, Inc., 113 FERC ] 61,239 at
P 7.
---------------------------------------------------------------------------
997. We also disagree that there is no reason to distinguish
between RTOs/ISOs and other transmission providers in considering
requests to amend the liability standard of their OATTs. The Commission
has provided increased liability protection to RTOs/ISOs because they
were created by and are solely regulated by the Commission and
otherwise would be without limitations on liability.\371\ Because
Washington IOUs have failed to show that other transmission providers
are similarly situated to RTOs/ISOs in this regard, we affirm the
decision to continue to review on a case-by-case basis a request to
amend the liability standard in a transmission provider's OATT.
---------------------------------------------------------------------------
\371\ See id.
---------------------------------------------------------------------------
9. OATT Definitions
998. In order to support the reforms adopted in Order No. 890 and
otherwise clarify the requirements of the pro forma OATT, the
Commission added and amended various definitions in the pro forma OATT.
Petitioners have sought rehearing and clarification of certain of these
definitions.
a. Affiliate
999. In order to support reforms associated with the distribution
of operational penalties, the Commission adopted the following
definition of Affiliate in the pro forma OATT: ``With respect to a
corporation, partnership or other entity, each such other corporation,
partnership or other entity that directly or indirectly, through one or
more intermediaries, controls, is controlled by, or is under common
control with, such corporation, partnership or other entity.''
Requests for Rehearing and Clarification
1000. EEI states that the term Affiliate is used in several
provisions of the pro forma OATT that were not modified by Order No.
890. To avoid potential confusion, EEI requests that the Commission
amend the pro forma OATT to capitalize every use of the term.
1001. APPA requests that, consistent with Order No. 888-A, the
Commission clarify that public power joint agencies and their members
are not corporate affiliates and, therefore, the definition of
Affiliate does not apply to public power joint action agencies for the
purposes of applying the Standards of Conduct. APPA notes that the
Commission in Order No. 890 concluded that the definition of Affiliate
does not apply to G&T cooperatives and their member distribution
cooperatives. APPA argues that public power joint action agencies and
their members are similarly situated to G&T cooperatives and their
members and, as a result, the rationale set out in Order No. 888-A and
Order No. 890 applies equally to public power agencies joint action
agencies and their members.\372\ APPA suggests Commission policy that
supports not treating joint action agencies and their members as
consisting of ``single economic units'' also supports not treating
joint action agencies and their members as Affiliates.\373\
---------------------------------------------------------------------------
\372\ Citing Order No. 890 at P 1682 (citing Order No. 888-A at
30,286 and 30,366).
\373\ Citing Southwest Power Pool, 112 FERC ] 61,355 at P 23-24
(2005).
---------------------------------------------------------------------------
1002. E.ON U.S. requests guidance on how functionally unbundled
transmission providers should treat their generation function for
purposes of the pro forma OATT. E.ON U.S. states that its generation
and transmission functions are owned by the same corporate entity, but
are unbundled from each other for purposes of the Standards of Conduct.
As a result, E.ON U.S. contends that its generation and transmission
functions are not Affiliates because they are part of the same
corporate entity. E.ON U.S. asks the Commission to clarify whether it
intends to include a transmission provider's unbundled generation
function within the definition of Affiliate even if the generation
function is part of the same corporate entity.
Commission Determination
1003. The Commission grants rehearing, as requested by EEI, to
amend
[[Page 3106]]
the pro forma OATT such that every use of the term Affiliate is
capitalized. We agree with APPA that members of an umbrella joint
action agency are not Affiliates of the joint action agency within the
meaning of the pro forma OATT. We clarify in response to E.ON U.S.,
however, that the transmission function and generation function of a
single corporation are Affiliates. Each would be an entity under common
control, notwithstanding the fact that they are within the same
corporation.
b. Good Utility Practice
1004. In Order No. 890, the Commission incorporated the definition
of reliable operation in FPA section 215 into the definition of Good
Utility Practice in the pro forma OATT. As amended, the definition of
Good Utility Practice is: ``Any of the practices, methods and acts
engaged in or approved by a significant portion of the electric utility
industry during the relevant time period, or any of the practices,
methods and acts which, in the exercise of reasonable judgment in light
of the facts known at the time the decision was made, could have been
expected to accomplish the desired result at a reasonable cost
consistent with good business practices, reliability, safety and
expedition. Good Utility Practice is not intended to be limited to the
optimum practice, method, or act to the exclusion of all others, but
rather to be acceptable practices, methods, or acts generally accepted
in the region, including those practices required by Federal Power Act
section 215(a)(4).''
Requests for Rehearing and Clarification
1005. Xcel argues that revising the definition of Good Utility
Practice to include compliance with the mandatory reliability standards
of FPA section 215 inappropriately subjects transmission providers to
two separate enforcement schemes for alleged violations of the
reliability standards. Xcel suggests that the Commission eliminate from
the definition of Good Utility Practice the reference to practices
under FPA section 215. Xcel argues that this would not eliminate the
obligation of transmission providers or transmission owners to comply
with the mandatory reliability standards and, instead, would make such
compliance subject to enforcement and potential penalties under one
enforcement regime, as contemplated by Congress under the FPA.
1006. If the Commission does not eliminate the reference to
practices required by section 215, Xcel asks the Commission to clarify
that reliability standards that have not been approved under FPA
section 215 would not be enforceable as an OATT violation.\374\ Xcel
also argues that a violation of a mandatory reliability standard
approved by the Commission should be subject to enforcement only by the
ERO or applicable RE under the compliance and enforcement scheme
created by NERC and the Commission under FPA section 215. Xcel contends
it would subject FERC-jurisdictional transmission providers to ``double
jeopardy'' to allow a claim of an alleged violation of a mandatory
reliability standard to be pursued in both an OATT enforcement
proceeding and a section 215 enforcement proceeding. Finally, Xcel
argues that in no event should an alleged violation of a mandatory
reliability standard be subject to dual financial penalties through
separate enforcement actions by the Commission for an OATT violation
and by the ERO or RE for a reliability violation.
---------------------------------------------------------------------------
\374\ Citing Order No. 693 at P 302.
---------------------------------------------------------------------------
Commission Determination
1007. The Commission affirms the decision in Order No. 890 to
incorporate within the definition of Good Utility Practice those
practices required by FPA section 215(a)(4). Even without the revisions
adopted in Order No. 890, the definition of Good Utility Practice would
have incorporated each reliability standard approved by the Commission,
since they represent practices in which the industry is required to
engage. The Commission simply made this explicit in Order No. 890.
1008. As we explained in Order No. 693, however, the Commission
does not believe it would be appropriate to retain a dual mechanism to
enforce reliability standards both as Good Utility Practice and under
FPA section 215.\375\ The pro forma OATT only applies to entities
subject to our jurisdiction as public utilities under the FPA, while
section 215 defines more broadly our jurisdiction with respect to
mandatory reliability standards. We therefore do not intend to enforce,
as an OATT violation, compliance with any reliability standard approved
by the Commission under section 215. It is more appropriate for the
Commission to rely on its authority under section 215 to enforce
compliance with mandatory reliability standards.
---------------------------------------------------------------------------
\375\ See id.
---------------------------------------------------------------------------
c. Non-Firm Sales
1009. In order to clarify the obligations of network customers
under section 30.4 of the pro forma OATT, the Commission adopted the
following definition of Non-Firm Sales in the pro forma OATT: ``An
energy sale for which receipt or delivery may be interrupted for any
reason or no reason, without liability on the part of either the buyer
or seller.''
Requests for Rehearing and Clarification
1010. NRECA asks the Commission to clarify that a unit-contingent
contract is not a Non-Firm Sale within the meaning of the pro forma
OATT, which NRECA argues would make it ineligible for designation as a
network resource. NRECA states that unit-contingent contracts excuse
non-delivery only on account of constraints on the unit providing
service and not, more generally, for ``any reason'' or ``no reason.''
NRECA contends that such contracts are sufficiently firm to be
considered ``LU'' and ``IU'' service in FERC Form One Account 447 and
should likewise not be considered Non-Firm Sales under the pro forma
OATT.
1011. Southern questions whether system-firm sales that permit
curtailment without penalty to serve the seller's native load should be
treated as Non-Firm Sales for purposes of section 30.4 of the pro forma
OATT. Southern states that the Commission has considered the purchase
of a system-firm energy to be eligible for designation as a network
resource,\376\ but contends that it is ambiguous whether the seller
should consider those sales as a Non-Firm Sale. Southern argues that
treating such sales as Non-Firm Sales would assure internal consistency
within the pro forma OATT, foster liquidity in short-term wholesale
opportunity markets, and promote the efficient optimization of network
resources.
---------------------------------------------------------------------------
\376\ Citing WPPI.
---------------------------------------------------------------------------
1012. Washington IOUs argues that a contract that allows for
interruption to serve native load should be considered a Non-Firm Sale
even if there is a ``make whole'' penalty for the interruption.
Washington IOUs argue that a requirement that sales from a designated
network resource be recallable for service of native or network load
without any financial consequences would constitute an unnecessary
regulatory intrusion into wholesale electricity markets, and is not
necessary for reliability purposes.\377\
---------------------------------------------------------------------------
\377\ Washington IOUs argue that, now that the Commission has
enforcement authority for reliability under section 215 of the FPA,
there are avenues to address reliability concerns that are more
effective than the use of rules for designated network resources.
---------------------------------------------------------------------------
1013. TAPS express similar concerns, asking the Commission to
clarify that the definition of Non-Firm Sales includes transactions
that permit interruption for any or no reason
[[Page 3107]]
without penalty, even if the seller may entail some financial liability
for interruption. TAPS states that failure to deliver energy sold in a
day-ahead organized market creates an obligation to pay the real-time
LMP and potentially other charges, even though the power sale is not
generally considered firm. If this potential obligation is interpreted
as a liability for purposes of qualifying as a Non-Firm Sale, TAPS
concludes that sales into day-ahead organized markets cannot be made
from a network resource without first undesignating that resource,
which TAPS argues would be unduly burdensome and would discourage
network customers from making sales into those markets. TAPS contends
that network customers will be reluctant to undesignate their network
resources for fear that they would be unable to redesignate them in a
timely manner if they are needed to serve native load in real-time.
1014. With regard to the MISO market in particular, TAPS argues
that refusing to treat sales into that day-ahead market as Non-Firm
Sales would require network customers to undesignate resources to
comply with MISO's must offer requirements. TAPS argues that it would
be inappropriate to require undesignation of a network resource to sell
into the RTO in which the resource is located as well as neighboring
RTOs, such as from MISO into PJM. The use of centralized dispatch in
these markets, TAPS argues, eliminates any effect temporary resource
undesignations and redesignations may have on dispatch or ATC
calculations. TAPS contends that the added burden of undesignating and
redesignating network resources is therefore pointless in centrally
dispatched markets.
1015. E.ON LSE expresses similar concerns, arguing that the
definition of Non-Firm Sale in combination with restricted network
resource designation policies will result in fewer resources being made
available. With regard to the MISO market in particular, E.ON LSE
states that the MISO tariff requires that certain day-ahead
transactions are made on the condition that the selling generator
provide service on-demand. E.ON LSE similarly request that the
Commission clarify that day-ahead and real-time sales in MISO and other
RTO/ISO markets need not meet the definition of Non-Firm Sales.
Commission Determination
1016. The Commission agrees with NRECA that, under normal
circumstances, we would not expect a unit contingent agreement to fall
within the definition of a Non-Firm Sale since typically delivery can
only be interrupted for the specific reasons identified in the
underlying agreement. We also agree with Southern that, under normal
circumstances, a system sale that permits curtailment without penalty
to serve the seller's native load would fall within the definition of a
Non-Firm Sale since the seller would have the right to rely on that
capacity in the event it is needed to serve native load, which is the
Commission's principal concern in restricting sales from designated
network resources to Non-Firm Sales. Whether any particular contract
satisfies the definition of Non-Firm Sales, however, must be considered
based on the terms and conditions of that contract.
1017. We disagree with TAPS and Washington IOUs that the definition
of Non-Firm Sales includes transactions that permit interruption with
financial liability, whether make whole or limited to certain
penalties. In Order No. 890, the Commission clarified its existing
policy prohibiting network customers from making third-party sales from
a designated network resource if the third-party power purchase
agreement does not allow the seller to interrupt power sales to the
third party in order to serve the designated network load.\378\ The
Commission adopted the definition of Non-Firm Sales to identify more
clearly those types of sales that are permitted from designated network
resources, explaining that any interruption in service that would
create liability on the part of the seller would create conflicting
incentives regarding use of the network resource and, therefore, such
sale could not be made without first undesignating the resource.\379\
The Commission concluded that it would be inappropriate to adopt
commenter suggestions to relax the definition of a Non-Firm Sale to
include any sale that is not otherwise firm enough to be designated as
a network resource.\380\
---------------------------------------------------------------------------
\378\ See Order No. 890 at P 1539.
\379\ See id. at P 1692. The Commission's use of the word
``penalty'' in paragraph 1539 of Order No. 890 was not intended to
restrict the scope of Non-Firm Sales. As the Commission explained in
that paragraph, our concern is that there not be financial
incentives that compete with the network resource's obligations to
serve its network load. Interruption must therefore be allowed
without liability or penalty.
\380\ Id.
---------------------------------------------------------------------------
1018. We appreciate the concerns of E.ON LSE and TAPS regarding the
potential effect of this decision on RTO/ISO markets. It does not
follow, however, that the pro forma OATT must be amended to accommodate
the particular market operations of each RTO and ISO. RTOs and ISOs
have adopted many variations from the pro forma OATT to facilitate
development of their markets, with some entirely eliminating the
designation/undesignation requirements for network resources. As TAPS
explains, centralized dispatch in these markets may very well eliminate
any effect that temporary resource undesignations and redesignations
have on dispatch or ATC calculations and, therefore, tailoring the
rules governing the designation of network resources to each RTO/ISO
market could be appropriate.
1019. We note that MISO has adopted the pro forma definition of
Non-Firm Sales in its compliance filing in response to Order No. 890
and certain members of TAPS have argued in response that adoption of
that definition is inconsistent with the operation of the MISO
market.\381\ The Commission will address those arguments on review of
the MISO compliance filing. In the interim, we note that MISO retains
significant discretion in how to implement the undesignation
requirements for network resources. Pending development of OASIS
functionality for electronic submission of undesignations and
redesignations, each transmission provider may adopt business practices
governing the undesignation and redesignation of network resources.
While the Commission referenced the use of telefax or recorded
telephone lines to convey this information,\382\ the bid-based nature
of LMP markets may justify adoption of other procedures. We decline to
impose any particular requirements here regarding the designation and
undesignation of network resources selling in an RTO/ISO market, as it
is more appropriate to leave development of those requirements to each
transmission provider, in coordination with its stakeholders as
relevant.
---------------------------------------------------------------------------
\381\ See Supplemental Comments of Indiana Municipal Power
Agency, Lincoln Electric System, Madison Gas & Electric Company, and
Wisconsin Public Power Inc., Docket No. OA08-14-000 (Nov. 6, 2007).
\382\ See Order No. 890 at P 1543.
---------------------------------------------------------------------------
d. Commenter Proposals
1020. The Commission declined to adopt various commenter proposals
for modifications or additions to the definitions contained in the pro
forma OATT. For example, the Commission declined to revise the
definition of Long-Term Firm Point-to-Point Transmission Service to
include service longer than one year, instead of one year or longer.
The Commission also rejected commenter requests to adopt proposed
definitions for the terms ``source,''
[[Page 3108]]
``sink,'' ``use,'' and ``transmission peak'' in the pro forma
OATT.\383\
---------------------------------------------------------------------------
\383\ Powerex's request for rehearing of the Commission's
decision not to modify the definition of System Impact Study to
exclude short-term service requests is discussed in section
III.D.4.a.(6) above.
---------------------------------------------------------------------------
Requests for Rehearing and Clarification
1021. Ameren argues that the Commission failed to adequately
consider its proposal to amend the definition of long-term firm service
to include only contracts that are longer than a year. Ameren argues
that contracts of only one year in duration should be reflected as a
revenue credit and that the current definition of long-term service
makes calculation very difficult in the modern RTO/Seams Elimination
Cost Allocation (SECA) environment. Ameren contends that the
Commission's refusal to modify the definition of long-term service is
inconsistent with other decisions in Order No. 890, such as the
requirement that the planning redispatch and conditional firm options
for long-term firm point-to-point service apply be offered only to
customers requesting service of more than a year in duration \384\ and
the intended planning benefits associated with granting rollover rights
only to customers with contracts of five years or longer.
---------------------------------------------------------------------------
\384\ Citing Order No. 890 at P 978.
---------------------------------------------------------------------------
1022. Ameren also challenges the Commission's rejection of an
alternative definition for ``transmission peak,'' arguing that the
current definition and calculation methodology is unworkable because
the data necessary no longer resides with the transmission owner.
Ameren further states that the Commission failed to adequately explain
rejection of proposed definitions of ``source'' and ``sink'' in section
22.2 of the pro forma OATT, and clarification whether the word ``use''
in section 30.8 of the pro forma OATT includes load ratio limitations,
although Ameren states no arguments in support of that contention.
Commission Determination
1023. The Commission affirms the decision in Order No. 890 to
maintain the current definition of Long-Term Firm Point-to-Point
Service. The definition is well-established in Commission precedent
and, notwithstanding Ameren's arguments to the contrary, consistent
with the reforms adopted in Order No. 890.\385\ Ameren has failed to
justify altering the definition of Long-Term Firm Point-to-Point
Service in light of the disruption such a change would cause.
---------------------------------------------------------------------------
\385\ The Commission clarifies in section III.D.1 our intent
that the conditional firm and planning redispatch options apply to
all long-term firm point-to-point requests for service, i.e.,
service of one year or longer.
---------------------------------------------------------------------------
1024. We also decline to amend the pro forma OATT to adopt Ameren's
proposed definitions of ``transmission peak,'' ``source,'' ``sink,''
and ``use.'' Ameren simply repeats arguments that have previously been
rejected. While peak load data ultimately resides with the RTO or ISO
in those regions, each transmission owner coordinates this data with
the RTO/ISO and, therefore, it is not necessary to alter the definition
of transmission peak as suggested by Ameren. The Commission has
adequately addressed the definitions of ``source'' and ``sink'' in
Order No. 888 and OASIS related proceedings and Ameren fails to state
why, in its view, additional clarification is needed. Finally, the
Commission has made clear that there are no load ratio limitations on
the use of interfaces under section 30.8 of the pro forma OATT.\386\
---------------------------------------------------------------------------
\386\ See Order No. 888 at 31,753-54; Order No. 888-A at 30,304-
5; see also Sierra Pacific Power Co., 81 FERC ] 61,136 at 61,139-40
(1997); New England Power Pool, 83 FERC ] 61,045 at 61,248 (1998).
---------------------------------------------------------------------------
E. Enforcement
1025. The Commission addressed several matters regarding
enforcement of the pro forma OATT in Order No. 890. Among other things,
the Commission concluded that it would revoke an entity's market-based
rate authority in response to an OATT violation only upon a finding of
a specific factual nexus between the violation and the entity's market-
based rate authority.\387\ The Commission reasoned that the ``nexus
condition'' is required in order to ensure that the Commission's
actions are not arbitrary or capricious or based on an inadequate
factual record. The Commission noted that in such situations it would
have the burden to show a factual nexus and did not assign a burden on
the violator to show a lack of nexus.
---------------------------------------------------------------------------
\387\ Order No. 890 at P 1743.
---------------------------------------------------------------------------
1026. The Commission disagreed that a finding of a ``serious'' or
``material'' violation of the OATT alone would be sufficient to justify
revocation of an entity's market-based rate authority. The Commission
concluded that the nexus condition requires a finding both that a
substantial OATT violation has occurred and that the violation either
related to the exercise of the violator's market-based rate authority
or violated a specific condition of that authority.\388\ The Commission
emphasized, moreover, that it has discretion to fashion further
sanctions, such as civil penalties or modification of a violator's
market-based rate authority, for OATT violations that relate to the
violator's market-based rate authority where a factual nexus
justification was not found to justify revocation of that authority.
---------------------------------------------------------------------------
\388\ Id. at P 1744.
---------------------------------------------------------------------------
1027. The Commission also created a rebuttable presumption that all
of the transmission provider's affiliates should lose their market-
based rate authority in each market in which their affiliated
transmission provider loses its market-based rate authority as a result
of an OATT violation.\389\ The Commission stated that it would allow an
affiliate of a transmission provider to retain its market-based rate
authority in a market area if the affiliate overcomes the rebuttable
presumption with respect to that market area. To afford due process to
a transmission provider's affiliates and to ensure that revocation of
market-based rate authority in a particular market for the transmission
provider and all of its affiliates is adequately based upon record
evidence and not arbitrary or capricious, the Commission provided that
each such affiliate will be allowed to make a showing that it should
retain its market-based rate authority or that enforcement action
against it should be less severe than revocation.
---------------------------------------------------------------------------
\389\ Id. at P 1747.
---------------------------------------------------------------------------
1028. The Commission explained that whether an affiliate has
overcome the rebuttable presumption will depend on an analysis of
specific facts in the record. Relevant facts would include, but are not
limited to, whether: (1) The transmission provider and the affiliate
were under the same control; (2) the affiliate knew of, participated in
or was an accomplice to the OATT violation; (3) the affiliate assisted
the transmission provider in exercising market power; or (4) the
affiliate benefited from the violation.\390\
---------------------------------------------------------------------------
\390\ Id. at P 1748.
---------------------------------------------------------------------------
Requests for Rehearing and Clarification
1029. NRECA argues that it is unclear what would constitute a
sufficient factual nexus between an OATT violation and revocation of
the violator's market-based rate authority. NRECA suggests that the
Commission instead adopt the standard advocated by APPA in its NOPR
comments, which would require revocation of the affiliate's market-
based rate authority when there is any material violation of the
transmission provider's OATT that denies a customer access to just,
reasonable, nondiscriminatory, and comparable transmission service. If
the Commission retains the nexus
[[Page 3109]]
requirement as formulated in Order No. 890, NRECA asks that the
Commission provide an illustrative list of what types of violations
could constitute a sufficient nexus between an OATT violation and an
entity's market-based rate authority. NRECA urges the Commission to
specifically identify failure to comply with the planning requirements
of Order No. 890 as satisfying the nexus requirement.
1030. TDU Systems argue that the nexus requirement does not pay
adequate attention to the basic nature and purpose of the market-based
rate authorization and, in their view, the critical question is whether
the OATT violation is indicative of conditions in the market which are
significantly different from those upon which the market-based rate
authorization was premised. TDU Systems argue that a transmission
provider's violation of a material term of its OATT should serve as
prima facie evidence that the structures presumed to cabin the exercise
of monopoly power may not be adequate. Even if the transmission
provider has not violated its OATT explicitly in connection with the
market-based rate authorization, TDU Systems contend that the violation
may nonetheless promote conditions in which the transmission provider
could gain an advantage in future transactions. TDU Systems state
particular concern that failure to comply with the planning obligations
of Order No. 890 may not be associated with any specific exercise of
market-based rate authority, yet could foster conditions inconsistent
with the premises of unconstrained and competitive markets.
1031. EEI argues that, since there is no rebuttable presumption
with respect to a transmission provider's OATT violation and its
potential loss of market-based rate authority, there should be no
rebuttable presumption regarding the market-based rate authority of the
transmission provider's affiliates. EEI contends that the Commission's
Code of Conduct actually supports a presumption that a transmission
provider's OATT violation does not have any relation to the activities
of the marketing affiliate since, absent evidence to the contrary, the
utility and its energy affiliates should be presumed to be obeying the
Commission's separation of function requirements. EEI further argues
that the Commission's reference to allegations that transmission
providers have engaged in transactions with affiliates does not justify
adoption of a rebuttable presumption in instances in which there are no
transactions with affiliates that violated the OATT. EEI therefore asks
the Commission to grant rehearing and hold that the rebuttable
presumption applies only if there is a specific factual nexus between
the activities of the marketing affiliate and the OATT violation.
1032. Ameren similarly argues that most integrated utility
companies that have market-based rate authority have separated their
marketing activities into ``regulated'' traditional utility functions
and ``non-regulated'' power marketing functions and have further
separated their transmission and merchant energy functions. Ameren
states that these utilities' codes of conduct and the Commission's
Standards of Conduct severely restrict the sharing of information
within an integrated utility company or the possible benefit to
affiliates from an OATT violation. Ameren argues that the presumption
adopted by the Commission unreasonably assumes a lack of compliance
with these obligations and unfairly shifts the burden to the affiliate
to show that it has not engaged in bad acts.
1033. Ameren contends that a decision by the Commission to revoke a
transmission provider's market-based rate authority would indicate only
that the Commission has determined that sanction to be appropriate in
light of the transmission provider's actions. In Ameren's view, there
is no reason or basis to similarly sanction the transmission provider's
affiliate in the absence of a showing that the affiliate participated
in, or benefited from, the transmission provider's improper behavior.
Ameren also argues that the presumption is inconsistent with the
Commission's decision in Order No. 890 to allow non-offending
affiliates of the transmission provider to share in the distribution of
operating penalties. Finally, Ameren argues that revoking the market-
based rate authority of a utility because of the actions of an
affiliated transmission provider would unfairly harm the traditional
utility affiliate as well as its bundled customers since many
traditional utilities engage in sales at market-based rates to reduce
their overall cost of power.
1034. Southern asks that the Commission confirm and clarify that
the rebuttable presumption does not shift the ultimate burden of proof
to the transmission provider or its affiliates, but rather places a
burden of going forward on the affiliates, with the ultimate burden
remaining with the Commission or other proponents of a revocation
sanction. Southern suggests that the presentation of evidence that
rebuts the presumption should result in the burden of proof reverting
back to the Commission or the proponent of revocation.
1035. Southern also requests clarification of the relevant facts to
be considered by the Commission in determining whether a sanction less
severe than revocation of market-based rate authority may be
appropriate for an affiliate. Southern notes that the first relevant
fact noted by the Commission in paragraph 1748 of Order No. 890 is
whether the transmission provider and the affiliate were under ``the
same control.'' Southern questions what the Commission meant by that
language since a transmission provider is by definition under the same
corporate control as an affiliate.
Commission Determination
1036. The Commission denies rehearing of the decision in Order No.
890 to require a factual nexus between a substantial OATT violation and
the entity's market-based rate authority to justify revocation of that
authority. As the Commission explained in Order No. 890, the ``nexus
condition'' is required in order to ensure that our actions are not
arbitrary or capricious or based on an inadequate factual record. We
disagree with NRECA and TDU Systems that any material OATT violation
should justify revocation of the entity's market-based rate authority
since the violation may have no relation to the market-based rate
authority. In such circumstances, the Commission will consider such
other sanctions as may be appropriate. We also decline to provide an
illustrative list of examples that would constitute a sufficient nexus
between an entity's market-based rate authority and an OATT violation.
The factual circumstances involved in a claimed violation will be
unique to the company and, therefore, any such list would be
incomplete. This is especially true in light of continually developing
market conditions. We continue to believe that the determination of
what would be a sufficient factual nexus between an OATT violation and
revocation of the violator's market-based rate authority is best left
to case-by-case consideration.
1037. With regard to the transmission provider's planning
obligations, violations of the planning-related requirements of the pro
forma OATT may or may not have a sufficient factual nexus with the
transmission provider's market-based rate authority. A case-by-case
analysis will be necessary to determine if the violation justifies
revocation of the transmission provider's market-based rate authority.
While we agree with TDU Systems that a transmission provider's OATT
[[Page 3110]]
violations that are not explicitly connected with its market-based rate
authorization may nonetheless promote conditions in which the violator
could gain an advantage in future transactions, we note that this is
the precise result that we seek to avoid with this enforcement
provision. Therefore, we will apply the mechanisms adopted in Order No.
890 to aid us in determining, on a case-by-case basis if a particular
violation promotes conditions that will put that company at a future
advantage vis-[agrave]-vis its market-based rate authority.
1038. We also decline to adopt TDU Systems' suggestion that we
consider whether the OATT violation is indicative of conditions in the
market that are significantly different from those upon which the
market-based rate authorization was premised. When the revocation of
market-based rate authority is being considered, we will distinguish
between those violations resulting from a change in market conditions
upon which the market-based rate authority was granted (and which are
likely outside of the company's control) versus a clear violation
related to the company's market-based rate authority. It may be most
appropriate to address those violations resulting from changes in
market conditions with an amendment to the affected company's OATT or
market-based rate tariff.
1039. We also affirm the adoption of a rebuttable presumption that
all of the transmission provider's affiliates should lose their market-
based rate authority in each market in which their affiliated
transmission provider loses its market-based rate authority as a result
of an OATT violation.\391\ While we agree that, absent evidence to the
contrary, the transmission provider and its affiliates should be
presumed to be obeying the Commission's separation of function
requirements and Affiliate Restrictions, we disagree that this
undermines the rebuttable presumption adopted in Order No. 890. If a
violation has occurred that justifies revocation of the entity's
market-based rate authority, the violation must have related to that
market-based rate authority. Assuming that the Standards of Conduct and
Affiliate Restrictions were followed, the finding of a nexus between
the violation and the entity's market-based rate authority demonstrates
that the Standards of Conduct or Affiliate Restrictions did not
preclude the violation. An OATT violation by a transmission provider
that merits revocation of the transmission provider's market-based rate
authority will, at a minimum, raise the question whether the
transmission provider's affiliates continue to qualify for market-based
rates under the standards established by the Commission.
---------------------------------------------------------------------------
\391\ Accord Order No. 697 at P 424-427.
---------------------------------------------------------------------------
1040. Applying this rebuttable presumption to the transmission
provider's affiliates is not, as suggested by Ameren, inconsistent with
the Commission's decision in Order No. 890 to allow non-offending
affiliates of the transmission provider to share in the distribution of
unreserved use penalties.\392\ Unreserved use penalties are a mechanism
used to redress administrative violations of the OATT and can be
assessed on any transmission customer. It is therefore appropriate to
distribute those penalties to all non-offending customers, whether or
not affiliated with the transmission provider. Unreserved use penalties
do not rise to the level of the sanction of revocation of market-based
rate authority, to which the presumption applies.
---------------------------------------------------------------------------
\392\ Although Ameren refers more generally to operational
penalties, only unreserved use penalties may be distributed to
affiliated customers. Late study penalties are to be distributed
only to non-affiliated transmission customers. See Order No. 890 at
P 1351.
---------------------------------------------------------------------------
1041. We also disagree that there must be a showing of benefit by
the affiliate in order to revoke its market-based rate authority or
that potential economic harm to the transmission provider's bundled
customers categorically justifies an affiliate to continue making sales
at market-based rates to reduce the company's overall cost of power,
even if the affiliate should otherwise lose its market-based rate
authority. It is possible that a transmission provider could violate
its OATT with an intent to advantage an affiliated marketer that, in
turn, attempts to take advantage of the violation in the market but is
unsuccessful because of market conditions. Alternatively, the
affiliated marketer could be successful, gaining an unfair advantage
due to the transmission provider's OATT violation, but thereby earning
revenue that ultimately serves to lower the cost of supplies for the
company's bundled customers. In either of these circumstances, it could
be appropriate to revoke or modify the market-based rate authority of
the affiliate. Therefore, the facts of each violation must be
considered in order to determine if revocation of market-based rate
authority is an appropriate sanction.
1042. With regard to Southern's request for clarification
concerning the burden of proof to show that an affiliate should lose
its market-based rate authority, we confirm that the ultimate burden
remains with the Commission. The presumption does not constitute a
definitive finding that the affiliate's market-based rate authority
should be revoked and, thus, the affiliate has an opportunity to
demonstrate that revocation would not be appropriate under the facts
and circumstances at issue.\393\ The rebuttable presumption thus
satisfies the Commission's burden of going forward and shifts to the
affiliate the burden of presenting evidence rebutting the presumption.
The ultimate burden of proof remains with the Commission throughout
these proceedings, and it must base any finding on a review of the
factual record.\394\
---------------------------------------------------------------------------
\393\ The use of shifting burdens of proof is consistent with
Commission practice in other areas. See, e.g., AEP Power Mktg, Inc.,
108 FERC ] 61,026 (2004); Southern Companies Energy Mktg, Inc., 111
FERC ] 61,144 (2005).
\394\ See Order No. 890 at P 1743-48.
---------------------------------------------------------------------------
1043. We clarify in response to Southern that the reference to
whether ``the transmission provider and the affiliate were under the
same control'' in paragraph 1748 of Order No. 890 is intended to
reflect that the Commission will consider whether the affiliation
between the transmission provider and the affiliate is sufficient to
give either or a common parent control over both entities.
IV. Information Collection Statement
1044. The Office of Management and Budget (OMB) regulations require
that OMB approve certain information collection requirements imposed by
an agency.\395\ The revisions to the information collection
requirements for transmission providers adopted in Order No. 890 were
approved under OMB Control Nos. 1902-0233. This order further revises
these requirements in order to more clearly state the obligations
imposed in Order No. 890, but does not substantively alter those
requirements. OMB approval of this order is therefore unnecessary.
However, the Commission will send a copy of this order to OMB for
informational purposes only.
---------------------------------------------------------------------------
\395\ 5 CFR 1320.
---------------------------------------------------------------------------
V. Document Availability
1045. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First
[[Page 3111]]
Street, NE., Room 2A, Washington DC 20426.
1046. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
1047. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at
public.referenceroom@ferc.gov.
VI. Effective Date and Congressional Notification
1048. Changes to Order No. 890 adopted in this order on rehearing
will become effective March 17, 2008.
List of Subjects in 18 CFR Part 37
Conflict on interests, Electric power rates, Electric power plants,
Reporting and recordkeeping requirements.
By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
0
In consideration of the foregoing, the Commission amends part 37,
Chapter I, Title 18 of the Code of Federal Regulations, as follows:
PART 37--OPEN ACCESS SAME-TIME INFORMATION SYSTEMS
0
1. The authority citation for part 37 continues to read as follows:
Authority: 16 U.S.C. 791-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
0
2. Amend Sec. 37.6 as follows:
0
a. Paragraph (b)(3)(iv) is revised.
0
b. Paragraph (h)(1) introductory text is revised.
0
c. Paragraph (h)(3) introductory text is revised.
0
d. Paragraph (i) is revised.
Sec. 37.6 Information to be posted on the OASIS.
* * * * *
(b) * * *
(3) * * *
(iv) Daily load. The Transmission Provider must post on a daily
basis, its load forecast, including underlying assumptions, and actual
daily peak load for the prior day.
* * * * *
(h) Posting information summarizing the time to complete
transmission service request studies. (1) For each calendar quarter,
the Responsible Party must post the set of measures detailed in
paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section
related to the Responsible Party's processing of transmission service
request system impact studies and facilities studies. The Responsible
Party must calculate and post the measures in paragraph (h)(1)(i)
through paragraph (h)(1)(vi) of this section for requests for short-
term firm point-to-point transmission service, requests for long-term
firm point-to-point transmission service, and requests to designate a
new network resource or network load. When calculating the measures in
paragraph (h)(1)(i) through paragraph (h)(1)(iv) of this section, the
Responsible Party may aggregate requests for short-term firm point-to-
point service and requests for long-term firm point-to-point service,
but must calculate and post measures separately for transmission
service requests from Affiliates and transmission service requests from
Transmission Customers who are not Affiliates. The Responsible Party is
required to include in the calculations of the measures in paragraph
(h)(1)(i) through paragraph (h)(1)(vi) of this section all studies the
Responsible Party conducts of transmission service requests on another
Transmission Provider's OASIS.
* * * * *
(3) The Responsible Party will be required to post on OASIS the
measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this
section in the event the Responsible Party, for two consecutive
calendar quarters, completes more than twenty (20) percent of the
studies associated with requests for transmission service from entities
that are not Affiliates of the Responsible Party more than sixty (60)
days after the Responsible Party delivers the appropriate study
agreement. The Responsible Party will have to post the measures in
paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this section until
it processes at least ninety (90) percent of all studies within 60 days
after it has received the appropriate executed study agreement. For the
purposes of calculating the percent of studies completed more than
sixty (60) days after the Responsible Party delivers the appropriate
study agreement, the Responsible Party should aggregate all system
impact studies and facilities studies that it completes during the
reporting quarter.
* * * * *
(i) Posting data related to grants and denials of service. The
Responsible Party is required to post data each month listing, by path
or flowgate, the number of transmission service requests that have been
accepted and the number of transmission service requests that have been
denied during the prior month. This posting must distinguish between
the length of the service request (e.g., short-term or long-term
requests) and between the type of service requested (e.g., firm point-
to-point, non-firm point-to-point or network service). The posted data
must show:
(1) The number of non-Affiliate requests for transmission service
that have been rejected,
(2) The total number of non-Affiliate requests for transmission
service that have been made,
(3) The number of Affiliate requests for transmission service,
including requests by the transmission provider's merchant function to
designate a network resource or to procure secondary network service,
that have been rejected, and
(4) The total number of Affiliate requests for transmission
service, including requests by the transmission provider's merchant
function to designate, or terminate the designation of, a network
resource or to procure secondary network service, that have been made.
* * * * *
Note: The following appendix will not appear in the Code of
Federal Regulations.
Appendix A to the Preamble: Petitioner Acronyms
------------------------------------------------------------------------
Abbreviation Petitioner names
------------------------------------------------------------------------
Alcoa........................ Alcoa Inc. and Alcoa Power Generating
Inc.
Ameren....................... Ameren Services Company.
AMP-Ohio..................... American Municipal Power-Ohio, Inc.
APPA......................... American Public Power Association.
AWEA......................... American Wind Energy Association.
[[Page 3112]]
Areva........................ Areva T&D.
APS.......................... Arizona Public Service Company.
ATCLLC....................... American Transmission Company LLC.
Barclays..................... Barclays Bank PLC, Credit Suisse Energy
LLC, J. Aron & Co., and Morgan Stanley
Capital Group Inc.
Bonneville................... Bonneville Power Administration.
Constellation................ Constellation Energy Group, Inc.
Duke......................... Duke Energy Corp.
Dynegy....................... Dynegy Power Marketing, Inc., Entegra
Power Group LLC, LS Power Associates.
E.ON LSE..................... E.ON Load Serving Entity.
E.ON U.S..................... E.ON U.S. LLC.
East Texas Cooperatives...... East Texas Electric Cooperative, Inc.;
Northeast Texas Electric Cooperative,
Inc.; Sam Rayburn Generation and
Electric Cooperative, Inc. and Tex-La
Electric Cooperative of Texas, Inc.
EEI.......................... Edison Electric Institute.
EPSA......................... Electric Power Supply Association.
Entergy...................... Entergy Services, Inc.
Financial Service Joint Barclays Bank PLC, Credit Suisse Energy
Requestors. LLC, J. Aron & Company, and Morgan
Stanley Capital Group Inc.
FMPA......................... Florida Municipal Power Agency and
Midwest Municipal Transmission Group.
Florida Power................ Florida Power & Light Co.
Great Northern............... Great Northern Power Development, L.P.
Idaho Power.................. Idaho Power Co.
Indicated Commenters......... Dynegy Power Marketing, Inc., Entegra
Power Group LLC, and LS Power
Associates, L.P.
ISO/RTO Council.............. ISO/RTO Council.
Mark Lively.................. Mark B. Lively.
MidAmerican.................. MidAmerican Energy Company and
PacifiCorp.
MISO......................... Midwest Independent Transmission System
Operator, Inc.
Morgan Stanley............... Morgan Stanley Capital Group Inc.
National Grid................ National Grid USA.
NRECA........................ National Rural Electric Cooperative
Association.
NYISO........................ New York Independent System Operator.
New York Transmission Owners. Central Hudson Gas & Elec. Corp.,
Consolidated Edison Co. of New York,
Inc., LIPA, New York Power Authority,
New York State Electric & Gas Corp.,
Orange and Rockland Utilities, Inc., and
Rochester Gas and Electric Corp.
NCEMC........................ North Carolina Electric Membership
Corporation.
NCPA......................... Northern California Power Agency.
NorthWestern................. NorthWestern Corporation.
Old Dominion................. Old Dominion Electric Cooperative.
Pacific Northwest Parties.... Avista Corp., Bonneville Power
Administration, PacifiCorp, PNGC Power,
Portland General Electric Company, and
Puget Sound Energy, Inc.
PJM.......................... PJM Interconnection, LLC.
Powerex...................... Powerex Corp.
Progress Energy.............. Progress Energy, Inc. (Carolina Power &
Light Co. d/b/a Progress Energy
Carolinas, Inc. and Florida Power Corp.,
d/b/a Progress Energy Florida, Inc.).
PNM.......................... Public Service Company of New Mexico.
PSEG......................... Public Service Electric and Gas Company;
PSEG Power LLC; and PSEC Energy
Resources & Trade LLC (PSEG Companies).
REPIO........................ Renewable Energy and Public Interest
Organizations (The Project for
Sustainable FERC Energy Policy,
Environmental Law & Policy Center,
Illinois Citizens Utility Board, Natural
Resources Defense Council, Northwest
Energy Coalition, Pace Energy Project,
Renewable Northwest Project, West Wind
Wires, and Wind on Wires.
Sempra Global................ Sempra Global.
South Carolina E&G........... South Carolina Electric & Gas Company.
South Carolina Regulatory South Carolina Office of Regulatory
Staff. Staff.
Southern..................... Southern Company Services, Inc.
Steel Manufacturers Steel Manufacturers Association.
Association.
Tenaska...................... Tenaska Power Services, Co.
TranServ..................... TranServ International, Inc.
TAPS......................... Transmission Access Policy Study Group.
TDU Systems.................. Transmission Dependent Utilities Systems.
Unitil....................... Unitil Power Corp., Unitil Energy
Systems, Inc. and Fitchburg Gas and
Elec. Light Co.
Washington IOUs.............. Avista Corp. and Puget Sound Energy, Inc.
Williams..................... Williams Power Company, Inc.
Wisconsin Electric........... Wisconsin Electric Power Company.
WSPP......................... Western Systems Power Pool, Inc.
Xcel......................... Xcel Energy Services, Inc.
------------------------------------------------------------------------
Note: The following appendix will not appear in the Code of
Federal Regulations.
[[Page 3113]]
Appendix B to the Preamble: Post-Technical Conference Commenter Acronyms
------------------------------------------------------------------------
Abbreviation Commenter names
------------------------------------------------------------------------
Alabama Municipal............ Alabama Municipal Electric Authority.
APS and EEI.................. Arizona Public Service Company and Edison
Electric Institute.
Barrick Goldstrike Mines..... Barrick Goldstrike Mines Inc. and Barrick
Turquoise Ridge Inc.
Bonneville................... Bonneville Power Administration.
Duke Energy Carolinas........ Duke Energy Carolinas, LLC.
Duke and EEI................. Duke Energy Corp. and Edison Electric
Institute.
EPSA......................... Electric Power Supply Association.
Great Lakes.................. Great Lakes Utilities.
Hoosier...................... Hoosier Energy Rural Electric
Cooperative, Inc.
Kansas Power Pool............ Kansas Power Pool.
MISO......................... Midwest Independent Transmission System
Operator, Inc.
Morgan Stanley............... Morgan Stanley Capital Group Inc.
Pacific Northwest IOUs....... Avista Corp., Portland General Electric
Company, and Puget Sound Energy, Inc.
Powerex...................... Powerex Corp.
PNGC Power................... Pacific Northwest Generating Cooperative,
Inc.
PPC.......................... Public Power Council.
PPL Parties.................. PPL EnergyPlus, LLC, Lower Mount Bethel
Energy, LLC, PPL Brunner Island, LLC,
PPL Edgewood Energy, LLC, PPL Great
Works, LLC, PPL Holtwood, LLC, PPL
Maine, LLC, PPL Martins Creek, LLC, PPL
Montana, LLC, PPL Montour, LLC, PPL
Shoreham Energy, LLC, PPL Susquehanna,
LLC, PPL University Park, LLC, and PPL
Wallingford Energy LLC.
Reliant...................... Reliant Energy, Inc.
SCE and SDG&E................ Southern California Edison Co. and San
Diego Gas & Electric Co.
South Carolina E&G........... South Carolina Electric & Gas Company.
Southern..................... Southern Company Services, Inc.
Southwestern Utilities....... Arizona Public Service Company, El Paso
Electric Company, Nevada Power Company
and Sierra-Pacific Power Company, Public
Service Company of New Mexico, Salt
River Project, Tucson Electric Power
Company, and UNS Electric Inc.
TAPS and APPA................ Transmission Access Policy Study Group
and the American Public Power
Association.
TDU Systems.................. Transmission Dependent Utilities Systems.
WSPP......................... Western Systems Power Pool, Inc.
------------------------------------------------------------------------
Note: The following appendix will not appear in the Code of
Federal Regulations.
Appendix C to the Preamble: RM05-17-001, -002 & RM05-25-001, -002
(Issued)
Pro Forma Open Access Transmission Tariff
Table of Contents
I. Common Service Provisions
1 Definitions
1.1 Affiliate
1.2 Ancillary Services
1.3 Annual Transmission Costs
1.4 Application
1.5 Commission
1.6 Completed Application
1.7 Control Area
1.8 Curtailment
1.9 Delivering Party
1.10 Designated Agent
1.11 Direct Assignment Facilities
1.12 Eligible Customer
1.13 Facilities Study
1.14 Firm Point-To-Point Transmission Service
1.15 Good Utility Practice
1.16 Interruption
1.17 Load Ratio Share
1.18 Load Shedding
1.19 Long-Term Firm Point-To-Point Transmission Service
1.20 Native Load Customers
1.21 Network Customer
1.22 Network Integration Transmission Service
1.23 Network Load
1.24 Network Operating Agreement
1.25 Network Operating Committee
1.26 Network Resource
1.27 Network Upgrades
1.28 Non-Firm Point-To-Point Transmission Service
1.29 Non-Firm Sale
1.30 Open Access Same-Time Information System (OASIS)
1.31 Part I
1.32 Part II
1.33 Part III
1.34 Parties
1.35 Point(s) of Delivery
1.36 Point(s) of Receipt
1.37 Point-To-Point Transmission Service
1.38 Power Purchaser
1.39 Pre-Confirmed Application
1.40 Receiving Party
1.41 Regional Transmission Group (RTG)
1.42 Reserved Capacity
1.43 Service Agreement
1.44 Service Commencement Date
1.45 Short-Term Firm Point-To-Point Transmission Service
1.46 System Condition
1.47 System Impact Study
1.48 Third-Party Sale
1.49 Transmission Customer
1.50 Transmission Provider
1.51 Transmission Provider's Monthly Transmission System Peak
1.52 Transmission Service
1.53 Transmission System
2 Initial Allocation and Renewal Procedures
2.1 Initial Allocation of Available Transfer Capability
2.2 Reservation Priority For Existing Firm Service Customers
3 Ancillary Services
3.1 Scheduling, System Control and Dispatch Service
3.2 Reactive Supply and Voltage Control from Generation or Other
Sources Service
3.3 Regulation and Frequency Response Service
3.4 Energy Imbalance Service
3.5 Operating Reserve--Spinning Reserve Service
3.6 Operating Reserve--Supplemental Reserve Service
3.7 Generator Imbalance Service
4 Open Access Same-Time Information System (OASIS)
5 Local Furnishing Bonds
5.1 Transmission Providers That Own Facilities Financed by Local
Furnishing Bonds
5.2 Alternative Procedures for Requesting Transmission Service
6 Reciprocity
7 Billing and Payment
7.1 Billing Procedure
7.2 Interest on Unpaid Balances
7.3 Customer Default
8 Accounting For The Transmission Provider's Use of the Tariff
8.1 Transmission Revenues
8.2 Study Costs and Revenues
9 Regulatory Filings
10 Force Majeure and Indemnification
10.1 Force Majeure
10.2 Indemnification
11 Creditworthiness
12 Dispute Resolution Procedures
[[Page 3114]]
12.1 Internal Dispute Resolution Procedures
12.2 External Arbitration Procedures
12.3 Arbitration Decisions
12.4 Costs
12.5 Rights Under The Federal Power Act
II. Point-To-Point Transmission Service
13 Nature of Firm Point-To-Point Transmission Service
13.1 Term
13.2 Reservation Priority
13.3 Use of Firm Transmission Service by the Transmission
Provider
13.4 Service Agreements
13.5 Transmission Customer Obligations for Facility Additions or
Redispatch Costs
13.6 Curtailment of Firm Transmission Service
13.7 Classification of Firm Transmission Service
13.8 Scheduling of Firm Point-To-Point Transmission Service
14 Nature of Non-Firm Point-To-Point Transmission Service
14.1 Term
14.2 Reservation Priority
14.3 Use of Non-Firm Point-To-Point Transmission Service by the
Transmission Provider
14.4 Service Agreements
14.5 Classification of Non-Firm Point-To-Point Transmission
Service
14.6 Scheduling of Non-Firm Point-To-Point Transmission Service
14.7 Curtailment or Interruption of Service
15 Service Availability
15.1 General Conditions
15.2 Determination of Available Transfer Capability
15.3 Initiating Service in the Absence of an Executed Service
Agreement
15.4 Obligation To Provide Transmission Service That Requires
Expansion or Modification of the Transmission System, Redispatch or
Conditional Curtailment
15.5 Deferral of Service
15.6 Other Transmission Service Schedules
15.7 Real Power Losses
16 Transmission Customer Responsibilities
16.1 Conditions Required of Transmission Customers
16.2 Transmission Customer Responsibility for Third-Party
Arrangements
17 Procedures for Arranging Firm Point-To-Point Transmission
Service
17.1 Application
17.2 Completed Application
17.3 Deposit
17.4 Notice of Deficient Application
17.5 Response to a Completed Application
17.6 Execution of Service Agreement
17.7 Extensions for Commencement of Service
18 Procedures for Arranging Non-Firm Point-To-Point Transmission
Service
18.1 Application
18.2 Completed Application
18.3 Reservation of Non-Firm Point-To-Point Transmission Service
18.4 Determination of Available Transfer Capability
19 Additional Study Procedures for Firm Point-To-Point
Transmission Service Requests
19.1 Notice of Need for System Impact Study
19.2 System Impact Study Agreement and Cost Reimbursement
19.3 System Impact Study Procedures
19.4 Facilities Study Procedures
19.5 Facilities Study Modifications
19.6 Due Diligence in Completing New Facilities
19.7 Partial Interim Service
19.8 Expedited Procedures for New Facilities
19.9 Penalties for Failure To Meet Study Deadlines
20 Procedures if the Transmission Provider Is Unable To Complete
New Transmission Facilities for Firm Point-To-Point Transmission
Service
20.1 Delays in Construction of New Facilities
20.2 Alternatives to the Original Facility Additions
20.3 Refund Obligation for Unfinished Facility Additions
21 Provisions Relating to Transmission Construction and Services
on the Systems of Other Utilities
21.1 Responsibility for Third-Party System Additions
21.2 Coordination of Third-Party System Additions
22 Changes In Service Specifications
22.1 Modifications On a Non-Firm Basis
22.2 Modification On a Firm Basis
23 Sale or Assignment of Transmission Service
23.1 Procedures for Assignment or Transfer of Service
23.2 Limitations on Assignment or Transfer of Service
23.3 Information on Assignment or Transfer of Service
24 Metering and Power Factor Correction at Receipt and Delivery
Points(s)
24.1 Transmission Customer Obligations
24.2 Transmission Provider Access to Metering Data
24.3 Power Factor
25 Compensation for Transmission Service
26 Stranded Cost Recovery
27 Compensation for New Facilities and Redispatch Costs
III. Network Integration Transmission Service
28 Nature of Network Integration Transmission Service
28.1 Scope of Service
28.2 Transmission Provider Responsibilities
28.3 Network Integration Transmission Service
28.4 Secondary Service
28.5 Real Power Losses
28.6 Restrictions on Use of Service
29 Initiating Service
29.1 Condition Precedent for Receiving Service
29.2 Application Procedures
29.3 Technical Arrangements to be Completed Prior to
Commencement of Service
29.4 Network Customer Facilities
29.5 Filing of Service Agreement
30 Network Resources
30.1 Designation of Network Resources
30.2 Designation of New Network Resources
30.3 Termination of Network Resources
30.4 Operation of Network Resources
30.5 Network Customer Redispatch Obligation
30.6 Transmission Arrangements for Network Resources Not
Physically Interconnected With The Transmission Provider
30.7 Limitation on Designation of Network Resources
30.8 Use of Interface Capacity by the Network Customer
30.9 Network Customer Owned Transmission Facilities
31 Designation of Network Load
31.1 Network Load
31.2 New Network Loads Connected With the Transmission Provider
31.3 Network Load Not Physically Interconnected With the
Transmission Provider
31.4 New Interconnection Points
31.5 Changes in Service Requests
31.6 Annual Load and Resource Information Updates
32 Additional Study Procedures For Network Integration
Transmission Service Requests
32.1 Notice of Need for System Impact Study
32.2 System Impact Study Agreement and Cost Reimbursement
32.3 System Impact Study Procedures
32.4 Facilities Study Procedures
32.5 Penalties for Failure To Meet Study Deadlines
33 Load Shedding and Curtailments
33.1 Procedures
33.2 Transmission Constraints
33.3 Cost Responsibility for Relieving Transmission Constraints
33.4 Curtailments of Scheduled Deliveries
33.5 Allocation of Curtailments
33.6 Load Shedding
33.7 System Reliability
34 Rates and Charges
34.1 Monthly Demand Charge
34.2 Determination of Network Customer's Monthly Network Load
34.3 Determination of Transmission Provider's Monthly
Transmission System Load
34.4 Redispatch Charge
34.5 Stranded Cost Recovery
35 Operating Arrangements
35.1 Operation Under The Network Operating Agreement
35.2 Network Operating Agreement
35.3 Network Operating Committee
Schedule 1--Scheduling, System Control and Dispatch Service
Schedule 2--Reactive Supply and Voltage Control From Generation
Sources Service
Schedule 3--Regulation and Frequency Response Service
Schedule 4--Energy Imbalance Service
Schedule 5--Operating Reserve--Spinning Reserve Service
[[Page 3115]]
Schedule 6--Operating Reserve--Supplemental Reserve Service
Schedule 7--Long-Term Firm and Short-Term Firm Point-To-Point
Transmission Service
Schedule 8--Non-Firm Point-To-Point Transmission Service
Schedule 9--Generator Imbalance Service
Attachment A--Form of Service Agreement for Firm Point-To-Point
Transmission Service
Attachment A-1--Form of Service Agreement for the Resale,
Reassignment or Transfer of Point-To-Point Transmission Service
Attachment B--Form of Service Agreement for Non-Firm Point-To-Point
Transmission Service
Attachment C--Methodology To Assess Available Transfer Capability
Attachment D--Methodology for Completing a System Impact Study
Attachment E--Index of Point-To-Point Transmission Service Customers
Attachment F--Service Agreement for Network Integration Transmission
Service
Attachment G--Network Operating Agreement
Attachment H--Annual Transmission Revenue Requirement for Network
Integration Transmission Service
Attachment I--Index of Network Integration Transmission Service
Customers
Attachment J--Procedures for Addressing Parallel Flows
Attachment K--Transmission Planning Process
Attachment L--Creditworthiness Procedures
I. Common Service Provisions
1 Definitions
1.1 Affiliate
With respect to a corporation, partnership or other entity, each
such other corporation, partnership or other entity that directly or
indirectly, through one or more intermediaries, controls, is controlled
by, or is under common control with, such corporation, partnership or
other entity.
1.2 Ancillary Services
Those services that are necessary to support the transmission of
capacity and energy from resources to loads while maintaining reliable
operation of the Transmission Provider's Transmission System in
accordance with Good Utility Practice.
1.3 Annual Transmission Costs
The total annual cost of the Transmission System for purposes of
Network Integration Transmission Service shall be the amount specified
in Attachment H until amended by the Transmission Provider or modified
by the Commission.
1.4 Application
A request by an Eligible Customer for transmission service pursuant
to the provisions of the Tariff.
1.5 Commission
The Federal Energy Regulatory Commission.
1.6 Completed Application
An Application that satisfies all of the information and other
requirements of the Tariff, including any required deposit.
1.7 Control Area
An electric power system or combination of electric power systems
to which a common automatic generation control scheme is applied in
order to:
1. Match, at all times, the power output of the generators within
the electric power system(s) and capacity and energy purchased from
entities outside the electric power system(s), with the load within the
electric power system(s);
2. Maintain scheduled interchange with other Control Areas, within
the limits of Good Utility Practice;
3. Maintain the frequency of the electric power system(s) within
reasonable limits in accordance with Good Utility Practice; and
4. Provide sufficient generating capacity to maintain operating
reserves in accordance with Good Utility Practice.
1.8 Curtailment
A reduction in firm or non-firm transmission service in response to
a transfer capability shortage as a result of system reliability
conditions.
1.9 Delivering Party
The entity supplying capacity and energy to be transmitted at
Point(s) of Receipt.
1.10 Designated Agent
Any entity that performs actions or functions on behalf of the
Transmission Provider, an Eligible Customer, or the Transmission
Customer required under the Tariff.
1.11 Direct Assignment Facilities
Facilities or portions of facilities that are constructed by the
Transmission Provider for the sole use/benefit of a particular
Transmission Customer requesting service under the Tariff. Direct
Assignment Facilities shall be specified in the Service Agreement that
governs service to the Transmission Customer and shall be subject to
Commission approval.
1.12 Eligible Customer
i. Any electric utility (including the Transmission Provider and
any power marketer), Federal power marketing agency, or any person
generating electric energy for sale for resale is an Eligible Customer
under the Tariff. Electric energy sold or produced by such entity may
be electric energy produced in the United States, Canada or Mexico.
However, with respect to transmission service that the Commission is
prohibited from ordering by Section 212(h) of the Federal Power Act,
such entity is eligible only if the service is provided pursuant to a
state requirement that the Transmission Provider offer the unbundled
transmission service, or pursuant to a voluntary offer of such service
by the Transmission Provider.
ii. Any retail customer taking unbundled transmission service
pursuant to a state requirement that the Transmission Provider offer
the transmission service, or pursuant to a voluntary offer of such
service by the Transmission Provider, is an Eligible Customer under the
Tariff.
1.13 Facilities Study
An engineering study conducted by the Transmission Provider to
determine the required modifications to the Transmission Provider's
Transmission System, including the cost and scheduled completion date
for such modifications, that will be required to provide the requested
transmission service.
1.14 Firm Point-To-Point Transmission Service
Transmission Service under this Tariff that is reserved and/or
scheduled between specified Points of Receipt and Delivery pursuant to
Part II of this Tariff.
1.15 Good Utility Practice
Any of the practices, methods and acts engaged in or approved by a
significant portion of the electric utility industry during the
relevant time period, or any of the practices, methods and acts which,
in the exercise of reasonable judgment in light of the facts known at
the time the decision was made, could have been expected to accomplish
the desired result at a reasonable cost consistent with good business
practices, reliability, safety and expedition. Good Utility Practice is
not intended to be limited to the optimum practice, method, or act to
the exclusion of all others, but rather to be acceptable practices,
methods, or acts generally accepted in the region, including those
[[Page 3116]]
practices required by Federal Power Act section 215(a)(4).
1.16 Interruption
A reduction in non-firm transmission service due to economic
reasons pursuant to Section 14.7.
1.17 Load Ratio Share
Ratio of a Transmission Customer's Network Load to the Transmission
Provider's total load computed in accordance with Sections 34.2 and
34.3 of the Network Integration Transmission Service under Part III of
the Tariff and calculated on a rolling twelve month basis.
1.18 Load Shedding
The systematic reduction of system demand by temporarily decreasing
load in response to transmission system or area capacity shortages,
system instability, or voltage control considerations under Part III of
the Tariff.
1.19 Long-Term Firm Point-To-Point Transmission Service
Firm Point-To-Point Transmission Service under Part II of the
Tariff with a term of one year or more.
1.20 Native Load Customers
The wholesale and retail power customers of the Transmission
Provider on whose behalf the Transmission Provider, by statute,
franchise, regulatory requirement, or contract, has undertaken an
obligation to construct and operate the Transmission Provider's system
to meet the reliable electric needs of such customers.
1.21 Network Customer
An entity receiving transmission service pursuant to the terms of
the Transmission Provider's Network Integration Transmission Service
under Part III of the Tariff.
1.22 Network Integration Transmission Service
The transmission service provided under Part III of the Tariff.
1.23 Network Load
The load that a Network Customer designates for Network Integration
Transmission Service under Part III of the Tariff. The Network
Customer's Network Load shall include all load served by the output of
any Network Resources designated by the Network Customer. A Network
Customer may elect to designate less than its total load as Network
Load but may not designate only part of the load at a discrete Point of
Delivery. Where an Eligible Customer has elected not to designate a
particular load at discrete points of delivery as Network Load, the
Eligible Customer is responsible for making separate arrangements under
Part II of the Tariff for any Point-To-Point Transmission Service that
may be necessary for such non-designated load.
1.24 Network Operating Agreement
An executed agreement that contains the terms and conditions under
which the Network Customer shall operate its facilities and the
technical and operational matters associated with the implementation of
Network Integration Transmission Service under Part III of the Tariff.
1.25 Network Operating Committee
A group made up of representatives from the Network Customer(s) and
the Transmission Provider established to coordinate operating criteria
and other technical considerations required for implementation of
Network Integration Transmission Service under Part III of this Tariff.
1.26 Network Resource
Any designated generating resource owned, purchased or leased by a
Network Customer under the Network Integration Transmission Service
Tariff. Network Resources do not include any resource, or any portion
thereof, that is committed for sale to third parties or otherwise
cannot be called upon to meet the Network Customer's Network Load on a
non-interruptible basis, except for purposes of fulfilling obligations
under a Commission-approved reserve sharing program.
1.27 Network Upgrades
Modifications or additions to transmission-related facilities that
are integrated with and support the Transmission Provider's overall
Transmission System for the general benefit of all users of such
Transmission System.
1.28 Non-Firm Point-To-Point Transmission Service
Point-To-Point Transmission Service under the Tariff that is
reserved and scheduled on an as-available basis and is subject to
Curtailment or Interruption as set forth in Section 14.7 under Part II
of this Tariff. Non-Firm Point-To-Point Transmission Service is
available on a stand-alone basis for periods ranging from one hour to
one month.
1.29 Non-Firm Sale
An energy sale for which receipt or delivery may be interrupted for
any reason or no reason, without liability on the part of either the
buyer or seller.
1.30 Open Access Same-Time Information System (OASIS)
The information system and standards of conduct contained in Part
37 of the Commission's regulations and all additional requirements
implemented by subsequent Commission orders dealing with OASIS.
1.31 Part I
Tariff Definitions and Common Service Provisions contained in
Sections 2 through 12.
1.32 Part II
Tariff Sections 13 through 27 pertaining to Point-To-Point
Transmission Service in conjunction with the applicable Common Service
Provisions of Part I and appropriate Schedules and Attachments.
1.33 Part III
Tariff Sections 28 through 35 pertaining to Network Integration
Transmission Service in conjunction with the applicable Common Service
Provisions of Part I and appropriate Schedules and Attachments.
1.34 Parties
The Transmission Provider and the Transmission Customer receiving
service under the Tariff.
1.35 Point(s) of Delivery
Point(s) on the Transmission Provider's Transmission System where
capacity and energy transmitted by the Transmission Provider will be
made available to the Receiving Party under Part II of the Tariff. The
Point(s) of Delivery shall be specified in the Service Agreement for
Long-Term Firm Point-To-Point Transmission Service.
1.36 Point(s) of Receipt
Point(s) of interconnection on the Transmission Provider's
Transmission System where capacity and energy will be made available to
the Transmission Provider by the Delivering Party under Part II of the
Tariff. The Point(s) of Receipt shall be specified in the Service
Agreement for Long-Term Firm Point-To-Point Transmission Service.
1.37 Point-To-Point Transmission Service
The reservation and transmission of capacity and energy on either a
firm or non-firm basis from the Point(s) of Receipt to the Point(s) of
Delivery under Part II of the Tariff.
[[Page 3117]]
1.38 Power Purchaser
The entity that is purchasing the capacity and energy to be
transmitted under the Tariff.
1.39 Pre-Confirmed Application
An Application that commits the Eligible Customer to execute a
Service Agreement upon receipt of notification that the Transmission
Provider can provide the requested Transmission Service.
1.40 Receiving Party
The entity receiving the capacity and energy transmitted by the
Transmission Provider to Point(s) of Delivery.
1.41 Regional Transmission Group (RTG)
A voluntary organization of transmission owners, transmission users
and other entities approved by the Commission to efficiently coordinate
transmission planning (and expansion), operation and use on a regional
(and interregional) basis.
1.42 Reserved Capacity
The maximum amount of capacity and energy that the Transmission
Provider agrees to transmit for the Transmission Customer over the
Transmission Provider's Transmission System between the Point(s) of
Receipt and the Point(s) of Delivery under Part II of the Tariff.
Reserved Capacity shall be expressed in terms of whole megawatts on a
sixty (60) minute interval (commencing on the clock hour) basis.
1.43 Service Agreement
The initial agreement and any amendments or supplements thereto
entered into by the Transmission Customer and the Transmission Provider
for service under the Tariff.
1.44 Service Commencement Date
The date the Transmission Provider begins to provide service
pursuant to the terms of an executed Service Agreement, or the date the
Transmission Provider begins to provide service in accordance with
Section 15.3 or Section 29.1 under the Tariff.
1.45 Short-Term Firm Point-To-Point Transmission Service
Firm Point-To-Point Transmission Service under Part II of the
Tariff with a term of less than one year.
1.46 System Condition
A specified condition on the Transmission Provider's system or on a
neighboring system, such as a constrained transmission element or
flowgate, that may trigger Curtailment of Long-Term Firm Point-to-Point
Transmission Service using the curtailment priority pursuant to Section
13.6. Such conditions must be identified in the Transmission Customer's
Service Agreement.
1.47 System Impact Study
An assessment by the Transmission Provider of (i) the adequacy of
the Transmission System to accommodate a request for either Firm Point-
To-Point Transmission Service or Network Integration Transmission
Service and (ii) whether any additional costs may be incurred in order
to provide transmission service.
1.48 Third-Party Sale
Any sale for resale in interstate commerce to a Power Purchaser
that is not designated as part of Network Load under the Network
Integration Transmission Service.
1.49 Transmission Customer
Any Eligible Customer (or its Designated Agent) that (i) executes a
Service Agreement, or (ii) requests in writing that the Transmission
Provider file with the Commission, a proposed unexecuted Service
Agreement to receive transmission service under Part II of the Tariff.
This term is used in the Part I Common Service Provisions to include
customers receiving transmission service under Part II and Part III of
this Tariff.
1.50 Transmission Provider
The public utility (or its Designated Agent) that owns, controls,
or operates facilities used for the transmission of electric energy in
interstate commerce and provides transmission service under the Tariff.
1.51 Transmission Provider's Monthly Transmission System Peak
The maximum firm usage of the Transmission Provider's Transmission
System in a calendar month.
1.52 Transmission Service
Point-To-Point Transmission Service provided under Part II of the
Tariff on a firm and non-firm basis.
1.53 Transmission System
The facilities owned, controlled or operated by the Transmission
Provider that are used to provide transmission service under Part II
and Part III of the Tariff.
2 Initial Allocation and Renewal Procedures
2.1 Initial Allocation of Available Transfer Capability
For purposes of determining whether existing capability on the
Transmission Provider's Transmission System is adequate to accommodate
a request for firm service under this Tariff, all Completed
Applications for new firm transmission service received during the
initial sixty (60) day period commencing with the effective date of the
Tariff will be deemed to have been filed simultaneously. A lottery
system conducted by an independent party shall be used to assign
priorities for Completed Applications filed simultaneously. All
Completed Applications for firm transmission service received after the
initial sixty (60) day period shall be assigned a priority pursuant to
Section 13.2.
2.2 Reservation Priority for Existing Firm Service Customers
Existing firm service customers (wholesale requirements and
transmission-only, with a contract term of five years or more), have
the right to continue to take transmission service from the
Transmission Provider when the contract expires, rolls over or is
renewed. This transmission reservation priority is independent of
whether the existing customer continues to purchase capacity and energy
from the Transmission Provider or elects to purchase capacity and
energy from another supplier. If at the end of the contract term, the
Transmission Provider's Transmission System cannot accommodate all of
the requests for transmission service, the existing firm service
customer must agree to accept a contract term at least equal to the
longest competing request by any new Eligible Customer and to pay the
current just and reasonable rate, as approved by the Commission, for
such service; provided that, the firm service customer shall have a
right of first refusal at the end of such service only if the new
contract is for five years or more. The existing firm service customer
must provide notice to the Transmission Provider whether it will
exercise its right of first refusal no less than one year prior to the
expiration date of its transmission service agreement. This
transmission reservation priority for existing firm service customers
is an ongoing right that may be exercised at the end of all firm
contract terms of five years or longer. Service agreements subject to a
right of first refusal entered into prior to [the date of the
Transmission Provider's filing adopting
[[Page 3118]]
the reformed rollover language herein in compliance with Order No. 890]
or associated with a transmission service request received prior to
July 13, 2007, unless terminated, will become subject to the five year/
one year requirement on the first rollover date after [the date of the
Transmission Provider's filing adopting the reformed rollover language
herein in compliance with Order No. 890]; provided that, the one-year
notice requirement shall apply to such service agreements with five
years or more left in their terms as of the [date of the Transmission
Provider's filing adopting the reformed rollover language herein in
compliance with Order No. 890].
3 Ancillary Services
Ancillary Services are needed with transmission service to maintain
reliability within and among the Control Areas affected by the
transmission service. The Transmission Provider is required to provide
(or offer to arrange with the local Control Area operator as discussed
below), and the Transmission Customer is required to purchase, the
following Ancillary Services (i) Scheduling, System Control and
Dispatch, and (ii) Reactive Supply and Voltage Control from Generation
or Other Sources.
The Transmission Provider is required to offer to provide (or offer
to arrange with the local Control Area operator as discussed below) the
following Ancillary Services only to the Transmission Customer serving
load within the Transmission Provider's Control Area (i) Regulation and
Frequency Response, (ii) Energy Imbalance, (iii) Operating Reserve--
Spinning, and (iv) Operating Reserve--Supplemental. The Transmission
Customer serving load within the Transmission Provider's Control Area
is required to acquire these Ancillary Services, whether from the
Transmission Provider, from a third party, or by self-supply.
The Transmission Provider is required to provide (or offer to
arrange with the local Control Area Operator as discussed below), to
the extent it is physically feasible to do so from its resources or
from resources available to it, Generator Imbalance Service when
Transmission Service is used to deliver energy from a generator located
within its Control Area. The Transmission Customer using Transmission
Service to deliver energy from a generator located within the
Transmission Provider's Control Area is required to acquire Generator
Imbalance Service, whether from the Transmission Provider, from a third
party, or by self-supply.
The Transmission Customer may not decline the Transmission
Provider's offer of Ancillary Services unless it demonstrates that it
has acquired the Ancillary Services from another source. The
Transmission Customer must list in its Application which Ancillary
Services it will purchase from the Transmission Provider. A
Transmission Customer that exceeds its firm reserved capacity at any
Point of Receipt or Point of Delivery or an Eligible Customer that uses
Transmission Service at a Point of Receipt or Point of Delivery that it
has not reserved is required to pay for all of the Ancillary Services
identified in this section that were provided by the Transmission
Provider associated with the unreserved service. The Transmission
Customer or Eligible Customer will pay for Ancillary Services based on
the amount of transmission service it used but did not reserve.
If the Transmission Provider is a public utility providing
transmission service but is not a Control Area operator, it may be
unable to provide some or all of the Ancillary Services. In this case,
the Transmission Provider can fulfill its obligation to provide
Ancillary Services by acting as the Transmission Customer's agent to
secure these Ancillary Services from the Control Area operator. The
Transmission Customer may elect to (i) have the Transmission Provider
act as its agent, (ii) secure the Ancillary Services directly from the
Control Area operator, or (iii) secure the Ancillary Services
(discussed in Schedules 3, 4, 5, 6 and 9) from a third party or by
self-supply when technically feasible.
The Transmission Provider shall specify the rate treatment and all
related terms and conditions in the event of an unauthorized use of
Ancillary Services by the Transmission Customer.
The specific Ancillary Services, prices and/or compensation methods
are described on the Schedules that are attached to and made a part of
the Tariff. Three principal requirements apply to discounts for
Ancillary Services provided by the Transmission Provider in conjunction
with its provision of transmission service as follows: (1) Any offer of
a discount made by the Transmission Provider must be announced to all
Eligible Customers solely by posting on the OASIS, (2) any customer-
initiated requests for discounts (including requests for use by one's
wholesale merchant or an Affiliate's use) must occur solely by posting
on the OASIS, and (3) once a discount is negotiated, details must be
immediately posted on the OASIS. A discount agreed upon for an
Ancillary Service must be offered for the same period to all Eligible
Customers on the Transmission Provider's system. Sections 3.1 through
3.7 below list the seven Ancillary Services.
3.1 Scheduling, System Control and Dispatch Service
The rates and/or methodology are described in Schedule 1.
3.2 Reactive Supply and Voltage Control From Generation or Other
Sources Service
The rates and/or methodology are described in Schedule 2.
3.3 Regulation and Frequency Response Service
Where applicable the rates and/or methodology are described in
Schedule 3.
3.4 Energy Imbalance Service
Where applicable the rates and/or methodology are described in
Schedule 4.
3.5 Operating Reserve--Spinning Reserve Service
Where applicable the rates and/or methodology are described in
Schedule 5.
3.6 Operating Reserve--Supplemental Reserve Service
Where applicable the rates and/or methodology are described in
Schedule 6.
3.7 Generator Imbalance Service
Where applicable the rates and/or methodology are described in
Schedule 9.
4 Open Access Same-Time Information System (OASIS)
Terms and conditions regarding Open Access Same-Time Information
System and standards of conduct are set forth in 18 CFR Sec. 37 of the
Commission's regulations (Open Access Same-Time Information System and
Standards of Conduct for Public Utilities) and 18 C.F.R. Sec. 38 of
the Commission's regulations (Business Practice Standards and
Communication Protocols for Public Utilities). In the event available
transfer capability as posted on the OASIS is insufficient to
accommodate a request for firm transmission service, additional studies
may be required as provided by this Tariff pursuant to Sections 19 and
32.
The Transmission Provider shall post on OASIS and its public Web
site an electronic link to all rules, standards and practices that (i)
relate to the terms
[[Page 3119]]
and conditions of transmission service, (ii) are not subject to a North
American Energy Standards Board (NAESB) copyright restriction, and
(iii) are not otherwise included in this Tariff. The Transmission
Provider shall post on OASIS and on its public Web site an electronic
link to the NAESB Web site where any rules, standards and practices
that are protected by copyright may be obtained. The Transmission
Provider shall also post on OASIS and its public Web site an electronic
link to a statement of the process by which the Transmission Provider
shall add, delete or otherwise modify the rules, standards and
practices that are not included in this tariff. Such process shall set
forth the means by which the Transmission Provider shall provide
reasonable advance notice to Transmission Customers and Eligible
Customers of any such additions, deletions or modifications, the
associated effective date, and any additional implementation procedures
that the Transmission Provider deems appropriate.
5 Local Furnishing Bonds
5.1 Transmission Providers That Own Facilities Financed by Local
Furnishing Bonds
This provision is applicable only to Transmission Providers that
have financed facilities for the local furnishing of electric energy
with tax-exempt bonds, as described in Section 142(f) of the Internal
Revenue Code (``local furnishing bonds''). Notwithstanding any other
provision of this Tariff, the Transmission Provider shall not be
required to provide transmission service to any Eligible Customer
pursuant to this Tariff if the provision of such transmission service
would jeopardize the tax-exempt status of any local furnishing bond(s)
used to finance the Transmission Provider's facilities that would be
used in providing such transmission service.
5.2 Alternative Procedures for Requesting Transmission Service
(i) If the Transmission Provider determines that the provision of
transmission service requested by an Eligible Customer would jeopardize
the tax-exempt status of any local furnishing bond(s) used to finance
its facilities that would be used in providing such transmission
service, it shall advise the Eligible Customer within thirty (30) days
of receipt of the Completed Application.
(ii) If the Eligible Customer thereafter renews its request for the
same transmission service referred to in (i) by tendering an
application under Section 211 of the Federal Power Act, the
Transmission Provider, within ten (10) days of receiving a copy of the
Section 211 application, will waive its rights to a request for service
under Section 213(a) of the Federal Power Act and to the issuance of a
proposed order under Section 212(c) of the Federal Power Act. The
Commission, upon receipt of the Transmission Provider's waiver of its
rights to a request for service under Section 213(a) of the Federal
Power Act and to the issuance of a proposed order under Section 212(c)
of the Federal Power Act, shall issue an order under Section 211 of the
Federal Power Act. Upon issuance of the order under Section 211 of the
Federal Power Act, the Transmission Provider shall be required to
provide the requested transmission service in accordance with the terms
and conditions of this Tariff.
6 Reciprocity
A Transmission Customer receiving transmission service under this
Tariff agrees to provide comparable transmission service that it is
capable of providing to the Transmission Provider on similar terms and
conditions over facilities used for the transmission of electric energy
owned, controlled or operated by the Transmission Customer and over
facilities used for the transmission of electric energy owned,
controlled or operated by the Transmission Customer's corporate
Affiliates. A Transmission Customer that is a member of, or takes
transmission service from, a power pool, Regional Transmission Group,
Regional Transmission Organization (RTO), Independent System Operator
(ISO) or other transmission organization approved by the Commission for
the operation of transmission facilities also agrees to provide
comparable transmission service to the transmission-owning members of
such power pool and Regional Transmission Group, RTO, ISO or other
transmission organization on similar terms and conditions over
facilities used for the transmission of electric energy owned,
controlled or operated by the Transmission Customer and over facilities
used for the transmission of electric energy owned, controlled or
operated by the Transmission Customer's corporate Affiliates.
This reciprocity requirement applies not only to the Transmission
Customer that obtains transmission service under the Tariff, but also
to all parties to a transaction that involves the use of transmission
service under the Tariff, including the power seller, buyer and any
intermediary, such as a power marketer. This reciprocity requirement
also applies to any Eligible Customer that owns, controls or operates
transmission facilities that uses an intermediary, such as a power
marketer, to request transmission service under the Tariff. If the
Transmission Customer does not own, control or operate transmission
facilities, it must include in its Application a sworn statement of one
of its duly authorized officers or other representatives that the
purpose of its Application is not to assist an Eligible Customer to
avoid the requirements of this provision.
7 Billing and Payment
7.1 Billing Procedure
Within a reasonable time after the first day of each month, the
Transmission Provider shall submit an invoice to the Transmission
Customer for the charges for all services furnished under the Tariff
during the preceding month. The invoice shall be paid by the
Transmission Customer within twenty (20) days of receipt. All payments
shall be made in immediately available funds payable to the
Transmission Provider, or by wire transfer to a bank named by the
Transmission Provider.
7.2 Interest on Unpaid Balances
Interest on any unpaid amounts (including amounts placed in escrow)
shall be calculated in accordance with the methodology specified for
interest on refunds in the Commission's regulations at 18 CFR
35.19a(a)(2)(iii). Interest on delinquent amounts shall be calculated
from the due date of the bill to the date of payment. When payments are
made by mail, bills shall be considered as having been paid on the date
of receipt by the Transmission Provider.
7.3 Customer Default
In the event the Transmission Customer fails, for any reason other
than a billing dispute as described below, to make payment to the
Transmission Provider on or before the due date as described above, and
such failure of payment is not corrected within thirty (30) calendar
days after the Transmission Provider notifies the Transmission Customer
to cure such failure, a default by the Transmission Customer shall be
deemed to exist. Upon the occurrence of a default, the Transmission
Provider may initiate a proceeding with the Commission to terminate
service but shall not terminate service until the Commission so
approves any such request. In the event of a billing dispute between
the Transmission Provider and the
[[Page 3120]]
Transmission Customer, the Transmission Provider will continue to
provide service under the Service Agreement as long as the Transmission
Customer (i) continues to make all payments not in dispute, and (ii)
pays into an independent escrow account the portion of the invoice in
dispute, pending resolution of such dispute. If the Transmission
Customer fails to meet these two requirements for continuation of
service, then the Transmission Provider may provide notice to the
Transmission Customer of its intention to suspend service in sixty (60)
days, in accordance with Commission policy.
8 Accounting for the Transmission Provider's Use of the Tariff
The Transmission Provider shall record the following amounts, as
outlined below.
8.1 Transmission Revenues
Include in a separate operating revenue account or subaccount the
revenues it receives from Transmission Service when making Third-Party
Sales under Part II of the Tariff.
8.2 Study Costs and Revenues
Include in a separate transmission operating expense account or
subaccount, costs properly chargeable to expense that are incurred to
perform any System Impact Studies or Facilities Studies which the
Transmission Provider conducts to determine if it must construct new
transmission facilities or upgrades necessary for its own uses,
including making Third-Party Sales under the Tariff; and include in a
separate operating revenue account or subaccount the revenues received
for System Impact Studies or Facilities Studies performed when such
amounts are separately stated and identified in the Transmission
Customer's billing under the Tariff.
9 Regulatory Filings
Nothing contained in the Tariff or any Service Agreement shall be
construed as affecting in any way the right of the Transmission
Provider to unilaterally make application to the Commission for a
change in rates, terms and conditions, charges, classification of
service, Service Agreement, rule or regulation under Section 205 of the
Federal Power Act and pursuant to the Commission's rules and
regulations promulgated thereunder.
Nothing contained in the Tariff or any Service Agreement shall be
construed as affecting in any way the ability of any Party receiving
service under the Tariff to exercise its rights under the Federal Power
Act and pursuant to the Commission's rules and regulations promulgated
thereunder.
10 Force Majeure and Indemnification
10.1 Force Majeure
An event of Force Majeure means any act of God, labor disturbance,
act of the public enemy, war, insurrection, riot, fire, storm or flood,
explosion, breakage or accident to machinery or equipment, any
Curtailment, order, regulation or restriction imposed by governmental
military or lawfully established civilian authorities, or any other
cause beyond a Party's control. A Force Majeure event does not include
an act of negligence or intentional wrongdoing. Neither the
Transmission Provider nor the Transmission Customer will be considered
in default as to any obligation under this Tariff if prevented from
fulfilling the obligation due to an event of Force Majeure. However, a
Party whose performance under this Tariff is hindered by an event of
Force Majeure shall make all reasonable efforts to perform its
obligations under this Tariff.
10.2 Indemnification
The Transmission Customer shall at all times indemnify, defend, and
save the Transmission Provider harmless from, any and all damages,
losses, claims, including claims and actions relating to injury to or
death of any person or damage to property, demands, suits, recoveries,
costs and expenses, court costs, attorney fees, and all other
obligations by or to third parties, arising out of or resulting from
the Transmission Provider's performance of its obligations under this
Tariff on behalf of the Transmission Customer, except in cases of
negligence or intentional wrongdoing by the Transmission Provider.
11 Creditworthiness
The Transmission Provider will specify its Creditworthiness
procedures in Attachment L.
12 Dispute Resolution Procedures
12.1 Internal Dispute Resolution Procedures
Any dispute between a Transmission Customer and the Transmission
Provider involving transmission service under the Tariff (excluding
applications for rate changes or other changes to the Tariff, or to any
Service Agreement entered into under the Tariff, which shall be
presented directly to the Commission for resolution) shall be referred
to a designated senior representative of the Transmission Provider and
a senior representative of the Transmission Customer for resolution on
an informal basis as promptly as practicable. In the event the
designated representatives are unable to resolve the dispute within
thirty (30) days [or such other period as the Parties may agree upon]
by mutual agreement, such dispute may be submitted to arbitration and
resolved in accordance with the arbitration procedures set forth below.
12.2 External Arbitration Procedures
Any arbitration initiated under the Tariff shall be conducted
before a single neutral arbitrator appointed by the Parties. If the
Parties fail to agree upon a single arbitrator within ten (10) days of
the referral of the dispute to arbitration, each Party shall choose one
arbitrator who shall sit on a three-member arbitration panel. The two
arbitrators so chosen shall within twenty (20) days select a third
arbitrator to chair the arbitration panel. In either case, the
arbitrators shall be knowledgeable in electric utility matters,
including electric transmission and bulk power issues, and shall not
have any current or past substantial business or financial
relationships with any party to the arbitration (except prior
arbitration). The arbitrator(s) shall provide each of the Parties an
opportunity to be heard and, except as otherwise provided herein, shall
generally conduct the arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association and any
applicable Commission regulations or Regional Transmission Group rules.
12.3 Arbitration Decisions
Unless otherwise agreed, the arbitrator(s) shall render a decision
within ninety (90) days of appointment and shall notify the Parties in
writing of such decision and the reasons therefor. The arbitrator(s)
shall be authorized only to interpret and apply the provisions of the
Tariff and any Service Agreement entered into under the Tariff and
shall have no power to modify or change any of the above in any manner.
The decision of the arbitrator(s) shall be final and binding upon the
Parties, and judgment on the award may be entered in any court having
jurisdiction. The decision of the arbitrator(s) may be appealed solely
on the grounds that the conduct of the arbitrator(s), or the decision
itself, violated the standards set forth in the Federal Arbitration Act
and/or the Administrative Dispute Resolution Act. The final decision of
the arbitrator must also be filed with the Commission if it affects
jurisdictional
[[Page 3121]]
rates, terms and conditions of service or facilities.
12.4 Costs
Each Party shall be responsible for its own costs incurred during
the arbitration process and for the following costs, if applicable:
1. The cost of the arbitrator chosen by the Party to sit on the
three member panel and one half of the cost of the third arbitrator
chosen; or
2. One half the cost of the single arbitrator jointly chosen by the
Parties.
12.5 Rights Under the Federal Power Act
Nothing in this section shall restrict the rights of any party to
file a Complaint with the Commission under relevant provisions of the
Federal Power Act.
II. Point-To-Point Transmission Service
Preamble
The Transmission Provider will provide Firm and Non-Firm Point-To-
Point Transmission Service pursuant to the applicable terms and
conditions of this Tariff. Point-To-Point Transmission Service is for
the receipt of capacity and energy at designated Point(s) of Receipt
and the transfer of such capacity and energy to designated Point(s) of
Delivery.
13 Nature of Firm Point-To-Point Transmission Service
13.1 Term
The minimum term of Firm Point-To-Point Transmission Service shall
be one day and the maximum term shall be specified in the Service
Agreement.
13.2 Reservation Priority
(i) Long-Term Firm Point-To-Point Transmission Service shall be
available on a first-come, first-served basis, i.e., in the
chronological sequence in which each Transmission Customer has
requested service.
(ii) Reservations for Short-Term Firm Point-To-Point Transmission
Service will be conditional based upon the length of the requested
transaction or reservation. However, Pre-Confirmed Applications for
Short-Term Point-to-Point Transmission Service will receive priority
over earlier-submitted requests that are not Pre-Confirmed and that
have equal or shorter duration. Among requests or reservations with the
same duration and, as relevant, pre-confirmation status (pre-confirmed,
confirmed, or not confirmed), priority will be given to an Eligible
Customer's request or reservation that offers the highest price,
followed by the date and time of the request or reservation.
(iii) If the Transmission System becomes oversubscribed, requests
for service may preempt competing reservations up to the following
conditional reservation deadlines: one day before the commencement of
daily service, one week before the commencement of weekly service, and
one month before the commencement of monthly service. Before the
conditional reservation deadline, if available transfer capability is
insufficient to satisfy all requests and reservations, an Eligible
Customer with a reservation for shorter term service or equal duration
service and lower price has the right of first refusal to match any
longer term request or equal duration service with a higher price
before losing its reservation priority. A longer term competing request
for Short-Term Firm Point-To-Point Transmission Service will be granted
if the Eligible Customer with the right of first refusal does not agree
to match the competing request within 24 hours (or earlier if necessary
to comply with the scheduling deadlines provided in section 13.8) from
being notified by the Transmission Provider of a longer-term competing
request for Short-Term Firm Point-To-Point Transmission Service. When a
longer duration request preempts multiple shorter duration
reservations, the shorter duration reservations shall have simultaneous
opportunities to exercise the right of first refusal. Duration, price
and time of response will be used to determine the order by which the
multiple shorter duration reservations will be able to exercise the
right of first refusal. After the conditional reservation deadline,
service will commence pursuant to the terms of Part II of the Tariff.
(iv) Firm Point-To-Point Transmission Service will always have a
reservation priority over Non-Firm Point-To-Point Transmission Service
under the Tariff. All Long-Term Firm Point-To-Point Transmission
Service will have equal reservation priority with Native Load Customers
and Network Customers. Reservation priorities for existing firm service
customers are provided in Section 2.2.
13.3 Use of Firm Transmission Service by the Transmission Provider
The Transmission Provider will be subject to the rates, terms and
conditions of Part II of the Tariff when making Third-Party Sales under
(i) agreements executed on or after March 17, 2008 or (ii) agreements
executed prior to the aforementioned date that the Commission requires
to be unbundled, by the date specified by the Commission. The
Transmission Provider will maintain separate accounting, pursuant to
Section 8, for any use of the Point-To-Point Transmission Service to
make Third-Party Sales.
13.4 Service Agreements
The Transmission Provider shall offer a standard form Firm Point-
To-Point Transmission Service Agreement (Attachment A) to an Eligible
Customer when it submits a Completed Application for Long-Term Firm
Point-To-Point Transmission Service. The Transmission Provider shall
offer a standard form Firm Point-To-Point Transmission Service
Agreement (Attachment A) to an Eligible Customer when it first submits
a Completed Application for Short-Term Firm Point-To-Point Transmission
Service pursuant to the Tariff. Executed Service Agreements that
contain the information required under the Tariff shall be filed with
the Commission in compliance with applicable Commission regulations. An
Eligible Customer that uses Transmission Service at a Point of Receipt
or Point of Delivery that it has not reserved and that has not executed
a Service Agreement will be deemed, for purposes of assessing any
appropriate charges and penalties, to have executed the appropriate
Service Agreement. The Service Agreement shall, when applicable,
specify any conditional curtailment options selected by the
Transmission Customer. Where the Service Agreement contains conditional
curtailment options and is subject to a biennial reassessment as
described in Section 15.4, the Transmission Provider shall provide the
Transmission Customer notice of any changes to the curtailment
conditions no less than 90 days prior to the date for imposition of new
curtailment conditions. Concurrent with such notice, the Transmission
Provider shall provide the Transmission Customer with the reassessment
study and a narrative description of the study, including the reasons
for changes to the number of hours per year or System Conditions under
which conditional curtailment may occur.
13.5 Transmission Customer Obligations for Facility Additions or
Redispatch Costs
In cases where the Transmission Provider determines that the
Transmission System is not capable of providing Firm Point-To-Point
Transmission Service without (1) degrading or impairing the reliability
of service to Native Load Customers, Network Customers and other
Transmission Customers taking Firm
[[Page 3122]]
Point-To-Point Transmission Service, or (2) interfering with the
Transmission Provider's ability to meet prior firm contractual
commitments to others, the Transmission Provider will be obligated to
expand or upgrade its Transmission System pursuant to the terms of
Section 15.4. The Transmission Customer must agree to compensate the
Transmission Provider for any necessary transmission facility additions
pursuant to the terms of Section 27. To the extent the Transmission
Provider can relieve any system constraint by redispatching the
Transmission Provider's resources, it shall do so, provided that the
Eligible Customer agrees to compensate the Transmission Provider
pursuant to the terms of Section 27 and agrees to either (i) compensate
the Transmission Provider for any necessary transmission facility
additions or (ii) accept the service subject to a biennial reassessment
by the Transmission Provider of redispatch requirements as described in
Section 15.4. Any redispatch, Network Upgrade or Direct Assignment
Facilities costs to be charged to the Transmission Customer on an
incremental basis under the Tariff will be specified in the Service
Agreement prior to initiating service.
13.6 Curtailment of Firm Transmission Service
In the event that a Curtailment on the Transmission Provider's
Transmission System, or a portion thereof, is required to maintain
reliable operation of such system and the system directly and
indirectly interconnected with Transmission Provider's Transmission
System, Curtailments will be made on a non-discriminatory basis to the
transaction(s) that effectively relieve the constraint. Transmission
Provider may elect to implement such Curtailments pursuant to the
Transmission Loading Relief procedures specified in Attachment J. If
multiple transactions require Curtailment, to the extent practicable
and consistent with Good Utility Practice, the Transmission Provider
will curtail service to Network Customers and Transmission Customers
taking Firm Point-To-Point Transmission Service on a basis comparable
to the curtailment of service to the Transmission Provider's Native
Load Customers. All Curtailments will be made on a non-discriminatory
basis, however, Non-Firm Point-To-Point Transmission Service shall be
subordinate to Firm Transmission Service. Long-Term Firm Point-to-Point
Service subject to conditions described in Section 15.4 shall be
curtailed with secondary service in cases where the conditions apply,
but otherwise will be curtailed on a pro rata basis with other Firm
Transmission Service. When the Transmission Provider determines that an
electrical emergency exists on its Transmission System and implements
emergency procedures to Curtail Firm Transmission Service, the
Transmission Customer shall make the required reductions upon request
of the Transmission Provider. However, the Transmission Provider
reserves the right to Curtail, in whole or in part, any Firm
Transmission Service provided under the Tariff when, in the
Transmission Provider's sole discretion, an emergency or other
unforeseen condition impairs or degrades the reliability of its
Transmission System. The Transmission Provider will notify all affected
Transmission Customers in a timely manner of any scheduled
Curtailments.
13.7 Classification of Firm Transmission Service
(a) The Transmission Customer taking Firm Point-To-Point
Transmission Service may (1) change its Receipt and Delivery Points to
obtain service on a non-firm basis consistent with the terms of Section
22.1 or (2) request a modification of the Points of Receipt or Delivery
on a firm basis pursuant to the terms of Section 22.2.
(b) The Transmission Customer may purchase transmission service to
make sales of capacity and energy from multiple generating units that
are on the Transmission Provider's Transmission System. For such a
purchase of transmission service, the resources will be designated as
multiple Points of Receipt, unless the multiple generating units are at
the same generating plant in which case the units would be treated as a
single Point of Receipt.
(c) The Transmission Provider shall provide firm deliveries of
capacity and energy from the Point(s) of Receipt to the Point(s) of
Delivery. Each Point of Receipt at which firm transmission capacity is
reserved by the Transmission Customer shall be set forth in the Firm
Point-To-Point Service Agreement for Long-Term Firm Transmission
Service along with a corresponding capacity reservation associated with
each Point of Receipt. Points of Receipt and corresponding capacity
reservations shall be as mutually agreed upon by the Parties for Short-
Term Firm Transmission. Each Point of Delivery at which firm transfer
capability is reserved by the Transmission Customer shall be set forth
in the Firm Point-To-Point Service Agreement for Long-Term Firm
Transmission Service along with a corresponding capacity reservation
associated with each Point of Delivery. Points of Delivery and
corresponding capacity reservations shall be as mutually agreed upon by
the Parties for Short-Term Firm Transmission. The greater of either (1)
the sum of the capacity reservations at the Point(s) of Receipt, or (2)
the sum of the capacity reservations at the Point(s) of Delivery shall
be the Transmission Customer's Reserved Capacity. The Transmission
Customer will be billed for its Reserved Capacity under the terms of
Schedule 7. The Transmission Customer may not exceed its firm capacity
reserved at each Point of Receipt and each Point of Delivery except as
otherwise specified in Section 22. The Transmission Provider shall
specify the rate treatment and all related terms and conditions
applicable in the event that a Transmission Customer (including Third-
Party Sales by the Transmission Provider) exceeds its firm reserved
capacity at any Point of Receipt or Point of Delivery or uses
Transmission Service at a Point of Receipt or Point of Delivery that it
has not reserved.
13.8 Scheduling of Firm Point-To-Point Transmission Service
Schedules for the Transmission Customer's Firm Point-To-Point
Transmission Service must be submitted to the Transmission Provider no
later than 10 a.m. [or a reasonable time that is generally accepted in
the region and is consistently adhered to by the Transmission Provider]
of the day prior to commencement of such service. Schedules submitted
after 10 a.m. will be accommodated, if practicable. Hour-to-hour
schedules of any capacity and energy that is to be delivered must be
stated in increments of 1,000 kW per hour [or a reasonable increment
that is generally accepted in the region and is consistently adhered to
by the Transmission Provider]. Transmission Customers within the
Transmission Provider's service area with multiple requests for
Transmission Service at a Point of Receipt, each of which is under
1,000 kW per hour, may consolidate their service requests at a common
point of receipt into units of 1,000 kW per hour for scheduling and
billing purposes. Scheduling changes will be permitted up to twenty
(20) minutes [or a reasonable time that is generally accepted in the
region and is consistently adhered to by the Transmission Provider]
before the start of the next clock hour provided that the Delivering
Party and Receiving Party also agree to the schedule modification. The
Transmission Provider will furnish to the Delivering Party's system
operator, hour-to-hour schedules equal to those furnished by the
Receiving Party (unless reduced for losses) and
[[Page 3123]]
shall deliver the capacity and energy provided by such schedules.
Should the Transmission Customer, Delivering Party or Receiving Party
revise or terminate any schedule, such party shall immediately notify
the Transmission Provider, and the Transmission Provider shall have the
right to adjust accordingly the schedule for capacity and energy to be
received and to be delivered.
14 Nature of Non-Firm Point-To-Point Transmission Service
14.1 Term
Non-Firm Point-To-Point Transmission Service will be available for
periods ranging from one (1) hour to one (1) month. However, a
Purchaser of Non-Firm Point-To-Point Transmission Service will be
entitled to reserve a sequential term of service (such as a sequential
monthly term without having to wait for the initial term to expire
before requesting another monthly term) so that the total time period
for which the reservation applies is greater than one month, subject to
the requirements of Section 18.3.
14.2 Reservation Priority
Non-Firm Point-To-Point Transmission Service shall be available
from transfer capability in excess of that needed for reliable service
to Native Load Customers, Network Customers and other Transmission
Customers taking Long-Term and Short-Term Firm Point-To-Point
Transmission Service. A higher priority will be assigned first to
requests or reservations with a longer duration of service and second
to Pre-Confirmed Applications. In the event the Transmission System is
constrained, competing requests of the same Pre-Confirmation status and
equal duration will be prioritized based on the highest price offered
by the Eligible Customer for the Transmission Service. Eligible
Customers that have already reserved shorter term service have the
right of first refusal to match any longer term request before being
preempted. A longer term competing request for Non-Firm Point-To-Point
Transmission Service will be granted if the Eligible Customer with the
right of first refusal does not agree to match the competing request:
(a) immediately for hourly Non-Firm Point-To-Point Transmission Service
after notification by the Transmission Provider; and, (b) within 24
hours (or earlier if necessary to comply with the scheduling deadlines
provided in section 14.6) for Non-Firm Point-To-Point Transmission
Service other than hourly transactions after notification by the
Transmission Provider. Transmission service for Network Customers from
resources other than designated Network Resources will have a higher
priority than any Non-Firm Point-To-Point Transmission Service. Non-
Firm Point-To-Point Transmission Service over secondary Point(s) of
Receipt and Point(s) of Delivery will have the lowest reservation
priority under the Tariff.
14.3 Use of Non-Firm Point-To-Point Transmission Service by the
Transmission Provider
The Transmission Provider will be subject to the rates, terms and
conditions of Part II of the Tariff when making Third-Party Sales under
(i) agreements executed on or after March 17, 2008 or (ii) agreements
executed prior to the aforementioned date that the Commission requires
to be unbundled, by the date specified by the Commission. The
Transmission Provider will maintain separate accounting, pursuant to
Section 8, for any use of Non-Firm Point-To-Point Transmission Service
to make Third-Party Sales.
14.4 Service Agreements
The Transmission Provider shall offer a standard form Non-Firm
Point-To-Point Transmission Service Agreement (Attachment B) to an
Eligible Customer when it first submits a Completed Application for
Non-Firm Point-To-Point Transmission Service pursuant to the Tariff.
Executed Service Agreements that contain the information required under
the Tariff shall be filed with the Commission in compliance with
applicable Commission regulations.
14.5 Classification of Non-Firm Point-To-Point Transmission Service
Non-Firm Point-To-Point Transmission Service shall be offered under
terms and conditions contained in Part II of the Tariff. The
Transmission Provider undertakes no obligation under the Tariff to plan
its Transmission System in order to have sufficient capacity for Non-
Firm Point-To-Point Transmission Service. Parties requesting Non-Firm
Point-To-Point Transmission Service for the transmission of firm power
do so with the full realization that such service is subject to
availability and to Curtailment or Interruption under the terms of the
Tariff. The Transmission Provider shall specify the rate treatment and
all related terms and conditions applicable in the event that a
Transmission Customer (including Third-Party Sales by the Transmission
Provider) exceeds its non-firm capacity reservation. Non-Firm Point-To-
Point Transmission Service shall include transmission of energy on an
hourly basis and transmission of scheduled short-term capacity and
energy on a daily, weekly or monthly basis, but not to exceed one
month's reservation for any one Application, under Schedule 8.
14.6 Scheduling of Non-Firm Point-To-Point Transmission Service
Schedules for Non-Firm Point-To-Point Transmission Service must be
submitted to the Transmission Provider no later than 2 p.m. [or a
reasonable time that is generally accepted in the region and is
consistently adhered to by the Transmission Provider] of the day prior
to commencement of such service. Schedules submitted after 2 p.m. will
be accommodated, if practicable. Hour-to-hour schedules of energy that
is to be delivered must be stated in increments of 1,000 kW per hour
[or a reasonable increment that is generally accepted in the region and
is consistently adhered to by the Transmission Provider]. Transmission
Customers within the Transmission Provider's service area with multiple
requests for Transmission Service at a Point of Receipt, each of which
is under 1,000 kW per hour, may consolidate their schedules at a common
Point of Receipt into units of 1,000 kW per hour. Scheduling changes
will be permitted up to twenty (20) minutes [or a reasonable time that
is generally accepted in the region and is consistently adhered to by
the Transmission Provider] before the start of the next clock hour
provided that the Delivering Party and Receiving Party also agree to
the schedule modification. The Transmission Provider will furnish to
the Delivering Party's system operator, hour-to-hour schedules equal to
those furnished by the Receiving Party (unless reduced for losses) and
shall deliver the capacity and energy provided by such schedules.
Should the Transmission Customer, Delivering Party or Receiving Party
revise or terminate any schedule, such party shall immediately notify
the Transmission Provider, and the Transmission Provider shall have the
right to adjust accordingly the schedule for capacity and energy to be
received and to be delivered.
14.7 Curtailment or Interruption of Service
The Transmission Provider reserves the right to Curtail, in whole
or in part, Non-Firm Point-To-Point Transmission Service provided under
the Tariff for reliability reasons when an emergency or other
unforeseen condition threatens to impair or degrade the reliability of
its Transmission System or the systems
[[Page 3124]]
directly and indirectly interconnected with Transmission Provider's
Transmission System. Transmission Provider may elect to implement such
Curtailments pursuant to the Transmission Loading Relief procedures
specified in Attachment J. The Transmission Provider reserves the right
to Interrupt, in whole or in part, Non-Firm Point-To-Point Transmission
Service provided under the Tariff for economic reasons in order to
accommodate (1) a request for Firm Transmission Service, (2) a request
for Non-Firm Point-To-Point Transmission Service of greater duration,
(3) a request for Non-Firm Point-To-Point Transmission Service of equal
duration with a higher price, (4) transmission service for Network
Customers from non-designated resources, or (5) transmission service
for Firm Point-To-Point Transmission Service during conditional
curtailment periods as described in Section 15.4. The Transmission
Provider also will discontinue or reduce service to the Transmission
Customer to the extent that deliveries for transmission are
discontinued or reduced at the Point(s) of Receipt. Where required,
Curtailments or Interruptions will be made on a non-discriminatory
basis to the transaction(s) that effectively relieve the constraint,
however, Non-Firm Point-To-Point Transmission Service shall be
subordinate to Firm Transmission Service. If multiple transactions
require Curtailment or Interruption, to the extent practicable and
consistent with Good Utility Practice, Curtailments or Interruptions
will be made to transactions of the shortest term (e.g., hourly non-
firm transactions will be Curtailed or Interrupted before daily non-
firm transactions and daily non-firm transactions will be Curtailed or
Interrupted before weekly non-firm transactions). Transmission service
for Network Customers from resources other than designated Network
Resources will have a higher priority than any Non-Firm Point-To-Point
Transmission Service under the Tariff. Non-Firm Point-To-Point
Transmission Service over secondary Point(s) of Receipt and Point(s) of
Delivery will have a lower priority than any Non-Firm Point-To-Point
Transmission Service under the Tariff. The Transmission Provider will
provide advance notice of Curtailment or Interruption where such notice
can be provided consistent with Good Utility Practice.
15 Service Availability
15.1 General Conditions
The Transmission Provider will provide Firm and Non-Firm Point-To-
Point Transmission Service over, on or across its Transmission System
to any Transmission Customer that has met the requirements of Section
16.
15.2 Determination of Available Transfer Capability
A description of the Transmission Provider's specific methodology
for assessing available transfer capability posted on the Transmission
Provider's OASIS (Section 4) is contained in Attachment C of the
Tariff. In the event sufficient transfer capability may not exist to
accommodate a service request, the Transmission Provider will respond
by performing a System Impact Study.
15.3 Initiating Service in the Absence of an Executed Service Agreement
If the Transmission Provider and the Transmission Customer
requesting Firm or Non-Firm Point-To-Point Transmission Service cannot
agree on all the terms and conditions of the Point-To-Point Service
Agreement, the Transmission Provider shall file with the Commission,
within thirty (30) days after the date the Transmission Customer
provides written notification directing the Transmission Provider to
file, an unexecuted Point-To-Point Service Agreement containing terms
and conditions deemed appropriate by the Transmission Provider for such
requested Transmission Service. The Transmission Provider shall
commence providing Transmission Service subject to the Transmission
Customer agreeing to (i) compensate the Transmission Provider at
whatever rate the Commission ultimately determines to be just and
reasonable, and (ii) comply with the terms and conditions of the Tariff
including posting appropriate security deposits in accordance with the
terms of Section 17.3.
15.4 Obligation To Provide Transmission Service That Requires Expansion
or Modification of the Transmission System, Redispatch or Conditional
Curtailment
(a) If the Transmission Provider determines that it cannot
accommodate a Completed Application for Firm Point-To-Point
Transmission Service because of insufficient capability on its
Transmission System, the Transmission Provider will use due diligence
to expand or modify its Transmission System to provide the requested
Firm Transmission Service, consistent with its planning obligations in
Attachment K, provided the Transmission Customer agrees to compensate
the Transmission Provider for such costs pursuant to the terms of
Section 27. The Transmission Provider will conform to Good Utility
Practice and its planning obligations in Attachment K, in determining
the need for new facilities and in the design and construction of such
facilities. The obligation applies only to those facilities that the
Transmission Provider has the right to expand or modify.
(b) If the Transmission Provider determines that it cannot
accommodate a Completed Application for Long-Term Firm Point-To-Point
Transmission Service because of insufficient capability on its
Transmission System, the Transmission Provider will use due diligence
to provide redispatch from its own resources until (i) Network Upgrades
are completed for the Transmission Customer, (ii) the Transmission
Provider determines through a biennial reassessment that it can no
longer reliably provide the redispatch, or (iii) the Transmission
Customer terminates the service because of redispatch changes resulting
from the reassessment. A Transmission Provider shall not unreasonably
deny self-provided redispatch or redispatch arranged by the
Transmission Customer from a third party resource.
(c) If the Transmission Provider determines that it cannot
accommodate a Completed Application for Long-Term Firm Point-To-Point
Transmission Service because of insufficient capability on its
Transmission System, the Transmission Provider will offer the Firm
Transmission Service with the condition that the Transmission Provider
may curtail the service prior to the curtailment of other Firm
Transmission Service for a specified number of hours per year or during
System Condition(s). If the Transmission Customer accepts the service,
the Transmission Provider will use due diligence to provide the service
until (i) Network Upgrades are completed for the Transmission Customer,
(ii) the Transmission Provider determines through a biennial
reassessment that it can no longer reliably provide such service, or
(iii) the Transmission Customer terminates the service because the
reassessment increased the number of hours per year of conditional
curtailment or changed the System Conditions.
15.5 Deferral of Service
The Transmission Provider may defer providing service until it
completes construction of new transmission facilities or upgrades
needed to provide Firm Point-To-Point Transmission
[[Page 3125]]
Service whenever the Transmission Provider determines that providing
the requested service would, without such new facilities or upgrades,
impair or degrade reliability to any existing firm services.
15.6 Other Transmission Service Schedules
Eligible Customers receiving transmission service under other
agreements on file with the Commission may continue to receive
transmission service under those agreements until such time as those
agreements may be modified by the Commission.
15.7 Real Power Losses
Real Power Losses are associated with all transmission service. The
Transmission Provider is not obligated to provide Real Power Losses.
The Transmission Customer is responsible for replacing losses
associated with all transmission service as calculated by the
Transmission Provider. The applicable Real Power Loss factors are as
follows: [To be completed by the Transmission Provider].
16 Transmission Customer Responsibilities
16.1 Conditions Required of Transmission Customers
Point-To-Point Transmission Service shall be provided by the
Transmission Provider only if the following conditions are satisfied by
the Transmission Customer:
(a) The Transmission Customer has pending a Completed Application
for service;
(b) The Transmission Customer meets the creditworthiness criteria
set forth in Section 11;
(c) The Transmission Customer will have arrangements in place for
any other transmission service necessary to effect the delivery from
the generating source to the Transmission Provider prior to the time
service under Part II of the Tariff commences;
(d) The Transmission Customer agrees to pay for any facilities
constructed and chargeable to such Transmission Customer under Part II
of the Tariff, whether or not the Transmission Customer takes service
for the full term of its reservation;
(e) The Transmission Customer provides the information required by
the Transmission Provider's planning process established in Attachment
K; and
(f) The Transmission Customer has executed a Point-To-Point Service
Agreement or has agreed to receive service pursuant to Section 15.3.
16.2 Transmission Customer Responsibility for Third-Party Arrangements
Any scheduling arrangements that may be required by other electric
systems shall be the responsibility of the Transmission Customer
requesting service. The Transmission Customer shall provide, unless
waived by the Transmission Provider, notification to the Transmission
Provider identifying such systems and authorizing them to schedule the
capacity and energy to be transmitted by the Transmission Provider
pursuant to Part II of the Tariff on behalf of the Receiving Party at
the Point of Delivery or the Delivering Party at the Point of Receipt.
However, the Transmission Provider will undertake reasonable efforts to
assist the Transmission Customer in making such arrangements, including
without limitation, providing any information or data required by such
other electric system pursuant to Good Utility Practice.
17 Procedures for Arranging Firm Point-To-Point Transmission Service
17.1 Application
A request for Firm Point-To-Point Transmission Service for periods
of one year or longer must contain a written Application to:
[Transmission Provider Name and Address], at least sixty (60) days in
advance of the calendar month in which service is to commence. The
Transmission Provider will consider requests for such firm service on
shorter notice when feasible. Requests for firm service for periods of
less than one year shall be subject to expedited procedures that shall
be negotiated between the Parties within the time constraints provided
in Section 17.5. All Firm Point-To-Point Transmission Service requests
should be submitted by entering the information listed below on the
Transmission Provider's OASIS. Prior to implementation of the
Transmission Provider's OASIS, a Completed Application may be submitted
by (i) transmitting the required information to the Transmission
Provider by telefax, or (ii) providing the information by telephone
over the Transmission Provider's time recorded telephone line. Each of
these methods will provide a time-stamped record for establishing the
priority of the Application.
17.2 Completed Application
A Completed Application shall provide all of the information
included in 18 CFR 2.20 including but not limited to the following:
(i) The identity, address, telephone number and facsimile number of
the entity requesting service;
(ii) A statement that the entity requesting service is, or will be
upon commencement of service, an Eligible Customer under the Tariff;
(iii) The location of the Point(s) of Receipt and Point(s) of
Delivery and the identities of the Delivering Parties and the Receiving
Parties;
(iv) The location of the generating facility(ies) supplying the
capacity and energy and the location of the load ultimately served by
the capacity and energy transmitted. The Transmission Provider will
treat this information as confidential except to the extent that
disclosure of this information is required by this Tariff, by
regulatory or judicial order, for reliability purposes pursuant to Good
Utility Practice or pursuant to RTG transmission information sharing
agreements. The Transmission Provider shall treat this information
consistent with the standards of conduct contained in Part 37 of the
Commission's regulations;
(v) A description of the supply characteristics of the capacity and
energy to be delivered;
(vi) An estimate of the capacity and energy expected to be
delivered to the Receiving Party;
(vii) The Service Commencement Date and the term of the requested
Transmission Service;
(viii) The transmission capacity requested for each Point of
Receipt and each Point of Delivery on the Transmission Provider's
Transmission System; customers may combine their requests for service
in order to satisfy the minimum transmission capacity requirement;
(ix) A statement indicating that, if the Eligible Customer submits
a Pre-Confirmed Application, the Eligible Customer will execute a
Service Agreement upon receipt of notification that the Transmission
Provider can provide the requested Transmission Service; and
(x) Any additional information required by the Transmission
Provider's planning process established in Attachment K.
The Transmission Provider shall treat this information consistent
with the standards of conduct contained in Part 37 of the Commission's
regulations.
17.3 Deposit
A Completed Application for Firm Point-To-Point Transmission
Service also shall include a deposit of either one month's charge for
Reserved Capacity or the full charge for Reserved Capacity for service
requests of less than one month.
[[Page 3126]]
If the Application is rejected by the Transmission Provider because it
does not meet the conditions for service as set forth herein, or in the
case of requests for service arising in connection with losing bidders
in a Request For Proposals (RFP), said deposit shall be returned with
interest less any reasonable costs incurred by the Transmission
Provider in connection with the review of the losing bidder's
Application. The deposit also will be returned with interest less any
reasonable costs incurred by the Transmission Provider if the
Transmission Provider is unable to complete new facilities needed to
provide the service. If an Application is withdrawn or the Eligible
Customer decides not to enter into a Service Agreement for Firm Point-
To-Point Transmission Service, the deposit shall be refunded in full,
with interest, less reasonable costs incurred by the Transmission
Provider to the extent such costs have not already been recovered by
the Transmission Provider from the Eligible Customer. The Transmission
Provider will provide to the Eligible Customer a complete accounting of
all costs deducted from the refunded deposit, which the Eligible
Customer may contest if there is a dispute concerning the deducted
costs. Deposits associated with construction of new facilities are
subject to the provisions of Section 19. If a Service Agreement for
Firm Point-To-Point Transmission Service is executed, the deposit, with
interest, will be returned to the Transmission Customer upon expiration
or termination of the Service Agreement for Firm Point-To-Point
Transmission Service. Applicable interest shall be computed in
accordance with the Commission's regulations at 18 CFR
35.19a(a)(2)(iii), and shall be calculated from the day the deposit
check is credited to the Transmission Provider's account.
17.4 Notice of Deficient Application
If an Application fails to meet the requirements of the Tariff, the
Transmission Provider shall notify the entity requesting service within
fifteen (15) days of receipt of the reasons for such failure. The
Transmission Provider will attempt to remedy minor deficiencies in the
Application through informal communications with the Eligible Customer.
If such efforts are unsuccessful, the Transmission Provider shall
return the Application, along with any deposit, with interest. Upon
receipt of a new or revised Application that fully complies with the
requirements of Part II of the Tariff, the Eligible Customer shall be
assigned a new priority consistent with the date of the new or revised
Application.
17.5 Response to a Completed Application
Following receipt of a Completed Application for Firm Point-To-
Point Transmission Service, the Transmission Provider shall make a
determination of available transfer capability as required in Section
15.2. The Transmission Provider shall notify the Eligible Customer as
soon as practicable, but not later than thirty (30) days after the date
of receipt of a Completed Application either (i) if it will be able to
provide service without performing a System Impact Study or (ii) if
such a study is needed to evaluate the impact of the Application
pursuant to Section 19.1. Responses by the Transmission Provider must
be made as soon as practicable to all completed applications (including
applications by its own merchant function) and the timing of such
responses must be made on a non-discriminatory basis.
17.6 Execution of Service Agreement
Whenever the Transmission Provider determines that a System Impact
Study is not required and that the service can be provided, it shall
notify the Eligible Customer as soon as practicable but no later than
thirty (30) days after receipt of the Completed Application. Where a
System Impact Study is required, the provisions of Section 19 will
govern the execution of a Service Agreement. Failure of an Eligible
Customer to execute and return the Service Agreement or request the
filing of an unexecuted service agreement pursuant to Section 15.3,
within fifteen (15) days after it is tendered by the Transmission
Provider will be deemed a withdrawal and termination of the Application
and any deposit submitted shall be refunded with interest. Nothing
herein limits the right of an Eligible Customer to file another
Application after such withdrawal and termination.
17.7 Extensions for Commencement of Service
The Transmission Customer can obtain, subject to availability, up
to five (5) one-year extensions for the commencement of service. The
Transmission Customer may postpone service by paying a non-refundable
annual reservation fee equal to one-month's charge for Firm
Transmission Service for each year or fraction thereof within 15 days
of notifying the Transmission Provider it intends to extend the
commencement of service. If during any extension for the commencement
of service an Eligible Customer submits a Completed Application for
Firm Transmission Service, and such request can be satisfied only by
releasing all or part of the Transmission Customer's Reserved Capacity,
the original Reserved Capacity will be released unless the following
condition is satisfied. Within thirty (30) days, the original
Transmission Customer agrees to pay the Firm Point-To-Point
transmission rate for its Reserved Capacity concurrent with the new
Service Commencement Date. In the event the Transmission Customer
elects to release the Reserved Capacity, the reservation fees or
portions thereof previously paid will be forfeited.
18 Procedures for Arranging Non-Firm Point-To-Point Transmission
Service
18.1 Application
Eligible Customers seeking Non-Firm Point-To-Point Transmission
Service must submit a Completed Application to the Transmission
Provider. Applications should be submitted by entering the information
listed below on the Transmission Provider's OASIS. Prior to
implementation of the Transmission Provider's OASIS, a Completed
Application may be submitted by (i) transmitting the required
information to the Transmission Provider by telefax, or (ii) providing
the information by telephone over the Transmission Provider's time
recorded telephone line. Each of these methods will provide a time-
stamped record for establishing the service priority of the
Application.
18.2 Completed Application
A Completed Application shall provide all of the information
included in 18 CFR 2.20 including but not limited to the following:
(i) The identity, address, telephone number and facsimile number of
the entity requesting service;
(ii) A statement that the entity requesting service is, or will be
upon commencement of service, an Eligible Customer under the Tariff;
(iii) The Point(s) of Receipt and the Point(s) of Delivery;
(iv) The maximum amount of capacity requested at each Point of
Receipt and Point of Delivery; and
(v) The proposed dates and hours for initiating and terminating
transmission service hereunder.
In addition to the information specified above, when required to
properly evaluate system conditions, the Transmission Provider also may
ask the Transmission Customer to provide the following:
(vi) The electrical location of the initial source of the power to
be
[[Page 3127]]
transmitted pursuant to the Transmission Customer's request for
service; and
(vii) The electrical location of the ultimate load.
The Transmission Provider will treat this information in (vi) and
(vii) as confidential at the request of the Transmission Customer
except to the extent that disclosure of this information is required by
this Tariff, by regulatory or judicial order, for reliability purposes
pursuant to Good Utility Practice, or pursuant to RTG transmission
information sharing agreements. The Transmission Provider shall treat
this information consistent with the standards of conduct contained in
Part 37 of the Commission's regulations.
(viii) A statement indicating that, if the Eligible Customer
submits a Pre-Confirmed Application, the Eligible Customer will execute
a Service Agreement upon receipt of notification that the Transmission
Provider can provide the requested Transmission Service.
18.3 Reservation of Non-Firm Point-To-Point Transmission Service
Requests for monthly service shall be submitted no earlier than
sixty (60) days before service is to commence; requests for weekly
service shall be submitted no earlier than fourteen (14) days before
service is to commence, requests for daily service shall be submitted
no earlier than two (2) days before service is to commence, and
requests for hourly service shall be submitted no earlier than noon the
day before service is to commence. Requests for service received later
than 2:00 p.m. prior to the day service is scheduled to commence will
be accommodated if practicable [or such reasonable times that are
generally accepted in the region and are consistently adhered to by the
Transmission Provider].
18.4 Determination of Available Transfer Capability
Following receipt of a tendered schedule the Transmission Provider
will make a determination on a non-discriminatory basis of available
transfer capability pursuant to Section 15.2. Such determination shall
be made as soon as reasonably practicable after receipt, but not later
than the following time periods for the following terms of service (i)
thirty (30) minutes for hourly service, (ii) thirty (30) minutes for
daily service, (iii) four (4) hours for weekly service, and (iv) two
(2) days for monthly service. [Or such reasonable times that are
generally accepted in the region and are consistently adhered to by the
Transmission Provider].
19 Additional Study Procedures for Firm Point-To-Point Transmission
Service Requests
19.1 Notice of Need for System Impact Study
After receiving a request for service, the Transmission Provider
shall determine on a non-discriminatory basis whether a System Impact
Study is needed. A description of the Transmission Provider's
methodology for completing a System Impact Study is provided in
Attachment D. If the Transmission Provider determines that a System
Impact Study is necessary to accommodate the requested service, it
shall so inform the Eligible Customer, as soon as practicable. Once
informed, the Eligible Customer shall timely notify the Transmission
Provider if it elects to have the Transmission Provider study
redispatch or conditional curtailment as part of the System Impact
Study. If notification is provided prior to tender of the System Impact
Study Agreement, the Eligible Customer can avoid the costs associated
with the study of these options. The Transmission Provider shall within
thirty (30) days of receipt of a Completed Application, tender a System
Impact Study Agreement pursuant to which the Eligible Customer shall
agree to reimburse the Transmission Provider for performing the
required System Impact Study. For a service request to remain a
Completed Application, the Eligible Customer shall execute the System
Impact Study Agreement and return it to the Transmission Provider
within fifteen (15) days. If the Eligible Customer elects not to
execute the System Impact Study Agreement, its application shall be
deemed withdrawn and its deposit, pursuant to Section 17.3, shall be
returned with interest.
19.2 System Impact Study Agreement and Cost Reimbursement
(i) The System Impact Study Agreement will clearly specify the
Transmission Provider's estimate of the actual cost, and time for
completion of the System Impact Study. The charge shall not exceed the
actual cost of the study. In performing the System Impact Study, the
Transmission Provider shall rely, to the extent reasonably practicable,
on existing transmission planning studies. The Eligible Customer will
not be assessed a charge for such existing studies; however, the
Eligible Customer will be responsible for charges associated with any
modifications to existing planning studies that are reasonably
necessary to evaluate the impact of the Eligible Customer's request for
service on the Transmission System.
(ii) If in response to multiple Eligible Customers requesting
service in relation to the same competitive solicitation, a single
System Impact Study is sufficient for the Transmission Provider to
accommodate the requests for service, the costs of that study shall be
pro-rated among the Eligible Customers.
(iii) For System Impact Studies that the Transmission Provider
conducts on its own behalf, the Transmission Provider shall record the
cost of the System Impact Studies pursuant to Section 20.
19.3 System Impact Study Procedures
Upon receipt of an executed System Impact Study Agreement, the
Transmission Provider will use due diligence to complete the required
System Impact Study within a sixty (60) day period. The System Impact
Study shall identify (1) any system constraints, identified with
specificity by transmission element or flowgate, (2) redispatch options
(when requested by an Eligible Customer) including an estimate of the
cost of redispatch, (3) conditional curtailment options (when requested
by an Eligible Customer) including the number of hours per year and the
System Conditions during which conditional curtailment may occur, and
(4) additional Direct Assignment Facilities or Network Upgrades
required to provide the requested service. For customers requesting the
study of redispatch options, the System Impact Study shall (1) identify
all resources located within the Transmission Provider's Control Area
that can significantly contribute toward relieving the system
constraint and (2) provide a measurement of each resource's impact on
the system constraint. If the Transmission Provider possesses
information indicating that any resource outside its Control Area could
relieve the constraint, it shall identify each such resource in the
System Impact Study. In the event that the Transmission Provider is
unable to complete the required System Impact Study within such time
period, it shall so notify the Eligible Customer and provide an
estimated completion date along with an explanation of the reasons why
additional time is required to complete the required studies. A copy of
the completed System Impact Study and related work papers shall be made
available to the Eligible Customer as soon as the System Impact Study
is complete. The Transmission Provider will use the same due diligence
in
[[Page 3128]]
completing the System Impact Study for an Eligible Customer as it uses
when completing studies for itself. The Transmission Provider shall
notify the Eligible Customer immediately upon completion of the System
Impact Study if the Transmission System will be adequate to accommodate
all or part of a request for service or that no costs are likely to be
incurred for new transmission facilities or upgrades. In order for a
request to remain a Completed Application, within fifteen (15) days of
completion of the System Impact Study the Eligible Customer must
execute a Service Agreement or request the filing of an unexecuted
Service Agreement pursuant to Section 15.3, or the Application shall be
deemed terminated and withdrawn.
19.4 Facilities Study Procedures
If a System Impact Study indicates that additions or upgrades to
the Transmission System are needed to supply the Eligible Customer's
service request, the Transmission Provider, within thirty (30) days of
the completion of the System Impact Study, shall tender to the Eligible
Customer a Facilities Study Agreement pursuant to which the Eligible
Customer shall agree to reimburse the Transmission Provider for
performing the required Facilities Study. For a service request to
remain a Completed Application, the Eligible Customer shall execute the
Facilities Study Agreement and return it to the Transmission Provider
within fifteen (15) days. If the Eligible Customer elects not to
execute the Facilities Study Agreement, its application shall be deemed
withdrawn and its deposit, pursuant to Section 17.3, shall be returned
with interest. Upon receipt of an executed Facilities Study Agreement,
the Transmission Provider will use due diligence to complete the
required Facilities Study within a sixty (60) day period. If the
Transmission Provider is unable to complete the Facilities Study in the
allotted time period, the Transmission Provider shall notify the
Transmission Customer and provide an estimate of the time needed to
reach a final determination along with an explanation of the reasons
that additional time is required to complete the study. When completed,
the Facilities Study will include a good faith estimate of (i) the cost
of Direct Assignment Facilities to be charged to the Transmission
Customer, (ii) the Transmission Customer's appropriate share of the
cost of any required Network Upgrades as determined pursuant to the
provisions of Part II of the Tariff, and (iii) the time required to
complete such construction and initiate the requested service. The
Transmission Customer shall provide the Transmission Provider with a
letter of credit or other reasonable form of security acceptable to the
Transmission Provider equivalent to the costs of new facilities or
upgrades consistent with commercial practices as established by the
Uniform Commercial Code. The Transmission Customer shall have thirty
(30) days to execute a Service Agreement or request the filing of an
unexecuted Service Agreement and provide the required letter of credit
or other form of security or the request will no longer be a Completed
Application and shall be deemed terminated and withdrawn.
19.5 Facilities Study Modifications
Any change in design arising from inability to site or construct
facilities as proposed will require development of a revised good faith
estimate. New good faith estimates also will be required in the event
of new statutory or regulatory requirements that are effective before
the completion of construction or other circumstances beyond the
control of the Transmission Provider that significantly affect the
final cost of new facilities or upgrades to be charged to the
Transmission Customer pursuant to the provisions of Part II of the
Tariff.
19.6 Due Diligence in Completing New Facilities
The Transmission Provider shall use due diligence to add necessary
facilities or upgrade its Transmission System within a reasonable time.
The Transmission Provider will not upgrade its existing or planned
Transmission System in order to provide the requested Firm Point-To-
Point Transmission Service if doing so would impair system reliability
or otherwise impair or degrade existing firm service.
19.7 Partial Interim Service
If the Transmission Provider determines that it will not have
adequate transfer capability to satisfy the full amount of a Completed
Application for Firm Point-To-Point Transmission Service, the
Transmission Provider nonetheless shall be obligated to offer and
provide the portion of the requested Firm Point-To-Point Transmission
Service that can be accommodated without addition of any facilities and
through redispatch. However, the Transmission Provider shall not be
obligated to provide the incremental amount of requested Firm Point-To-
Point Transmission Service that requires the addition of facilities or
upgrades to the Transmission System until such facilities or upgrades
have been placed in service.
19.8 Expedited Procedures for New Facilities
In lieu of the procedures set forth above, the Eligible Customer
shall have the option to expedite the process by requesting the
Transmission Provider to tender at one time, together with the results
of required studies, an ``Expedited Service Agreement'' pursuant to
which the Eligible Customer would agree to compensate the Transmission
Provider for all costs incurred pursuant to the terms of the Tariff. In
order to exercise this option, the Eligible Customer shall request in
writing an expedited Service Agreement covering all of the above-
specified items within thirty (30) days of receiving the results of the
System Impact Study identifying needed facility additions or upgrades
or costs incurred in providing the requested service. While the
Transmission Provider agrees to provide the Eligible Customer with its
best estimate of the new facility costs and other charges that may be
incurred, such estimate shall not be binding and the Eligible Customer
must agree in writing to compensate the Transmission Provider for all
costs incurred pursuant to the provisions of the Tariff. The Eligible
Customer shall execute and return such an Expedited Service Agreement
within fifteen (15) days of its receipt or the Eligible Customer's
request for service will cease to be a Completed Application and will
be deemed terminated and withdrawn.
19.9 Penalties for Failure To Meet Study Deadlines
Sections 19.3 and 19.4 require a Transmission Provider to use due
diligence to meet 60-day study completion deadlines for System Impact
Studies and Facilities Studies.
(i) The Transmission Provider is required to file a notice with the
Commission in the event that more than twenty (20) percent of non-
Affiliates' System Impact Studies and Facilities Studies completed by
the Transmission Provider in any two consecutive calendar quarters are
not completed within the 60-day study completion deadlines. Such notice
must be filed within thirty (30) days of the end of the calendar
quarter triggering the notice requirement.
(ii) For the purposes of calculating the percent of non-Affiliates'
System Impact Studies and Facilities Studies processed outside of the
60-day study completion deadlines, the Transmission Provider shall
consider all System Impact Studies and Facilities Studies that it
completes
[[Page 3129]]
for non-Affiliates during the calendar quarter. The percentage should
be calculated by dividing the number of those studies which are
completed on time by the total number of completed studies. The
Transmission Provider may provide an explanation in its notification
filing to the Commission if it believes there are extenuating
circumstances that prevented it from meeting the 60-day study
completion deadlines.
(iii) The Transmission Provider is subject to an operational
penalty if it completes ten (10) percent or more of non-Affiliates'
System Impact Studies and Facilities Studies outside of the 60-day
study completion deadlines for each of the two calendar quarters
immediately following the quarter that triggered its notification
filing to the Commission. The operational penalty will be assessed for
each calendar quarter for which an operational penalty applies,
starting with the calendar quarter immediately following the quarter
that triggered the Transmission Provider's notification filing to the
Commission. The operational penalty will continue to be assessed each
quarter until the Transmission Provider completes at least ninety (90)
percent of all non-Affiliates' System Impact Studies and Facilities
Studies within the 60-day deadline.
(iv) For penalties assessed in accordance with subsection (iii)
above, the penalty amount for each System Impact Study or Facilities
Study shall be equal to $500 for each day the Transmission Provider
takes to complete that study beyond the 60-day deadline.
20 Procedures if the Transmission Provider Is Unable To Complete New
Transmission Facilities for Firm Point-To-Point Transmission Service
20.1 Delays in Construction of New Facilities
If any event occurs that will materially affect the time for
completion of new facilities, or the ability to complete them, the
Transmission Provider shall promptly notify the Transmission Customer.
In such circumstances, the Transmission Provider shall within thirty
(30) days of notifying the Transmission Customer of such delays,
convene a technical meeting with the Transmission Customer to evaluate
the alternatives available to the Transmission Customer. The
Transmission Provider also shall make available to the Transmission
Customer studies and work papers related to the delay, including all
information that is in the possession of the Transmission Provider that
is reasonably needed by the Transmission Customer to evaluate any
alternatives.
20.2 Alternatives to the Original Facility Additions
When the review process of Section 20.1 determines that one or more
alternatives exist to the originally planned construction project, the
Transmission Provider shall present such alternatives for consideration
by the Transmission Customer. If, upon review of any alternatives, the
Transmission Customer desires to maintain its Completed Application
subject to construction of the alternative facilities, it may request
the Transmission Provider to submit a revised Service Agreement for
Firm Point-To-Point Transmission Service. If the alternative approach
solely involves Non-Firm Point-To-Point Transmission Service, the
Transmission Provider shall promptly tender a Service Agreement for
Non-Firm Point-To-Point Transmission Service providing for the service.
In the event the Transmission Provider concludes that no reasonable
alternative exists and the Transmission Customer disagrees, the
Transmission Customer may seek relief under the dispute resolution
procedures pursuant to Section 12 or it may refer the dispute to the
Commission for resolution.
20.3 Refund Obligation for Unfinished Facility Additions
If the Transmission Provider and the Transmission Customer mutually
agree that no other reasonable alternatives exist and the requested
service cannot be provided out of existing capability under the
conditions of Part II of the Tariff, the obligation to provide the
requested Firm Point-To-Point Transmission Service shall terminate and
any deposit made by the Transmission Customer shall be returned with
interest pursuant to Commission regulations 35.19a(a)(2)(iii). However,
the Transmission Customer shall be responsible for all prudently
incurred costs by the Transmission Provider through the time
construction was suspended.
21 Provisions Relating to Transmission Construction and Services on the
Systems of Other Utilities
21.1 Responsibility for Third-Party System Additions
The Transmission Provider shall not be responsible for making
arrangements for any necessary engineering, permitting, and
construction of transmission or distribution facilities on the
system(s) of any other entity or for obtaining any regulatory approval
for such facilities. The Transmission Provider will undertake
reasonable efforts to assist the Transmission Customer in obtaining
such arrangements, including without limitation, providing any
information or data required by such other electric system pursuant to
Good Utility Practice.
21.2 Coordination of Third-Party System Additions
In circumstances where the need for transmission facilities or
upgrades is identified pursuant to the provisions of Part II of the
Tariff, and if such upgrades further require the addition of
transmission facilities on other systems, the Transmission Provider
shall have the right to coordinate construction on its own system with
the construction required by others. The Transmission Provider, after
consultation with the Transmission Customer and representatives of such
other systems, may defer construction of its new transmission
facilities, if the new transmission facilities on another system cannot
be completed in a timely manner. The Transmission Provider shall notify
the Transmission Customer in writing of the basis for any decision to
defer construction and the specific problems which must be resolved
before it will initiate or resume construction of new facilities.
Within sixty (60) days of receiving written notification by the
Transmission Provider of its intent to defer construction pursuant to
this section, the Transmission Customer may challenge the decision in
accordance with the dispute resolution procedures pursuant to Section
12 or it may refer the dispute to the Commission for resolution.
22 Changes in Service Specifications
22.1 Modifications on a Non-Firm Basis
The Transmission Customer taking Firm Point-To-Point Transmission
Service may request the Transmission Provider to provide transmission
service on a non-firm basis over Receipt and Delivery Points other than
those specified in the Service Agreement (``Secondary Receipt and
Delivery Points''), in amounts not to exceed its firm capacity
reservation, without incurring an additional Non-Firm Point-To-Point
Transmission Service charge or executing a new Service Agreement,
subject to the following conditions.
(a) Service provided over Secondary Receipt and Delivery Points
will be non-firm only, on an as-available basis and
[[Page 3130]]
will not displace any firm or non-firm service reserved or scheduled by
third-parties under the Tariff or by the Transmission Provider on
behalf of its Native Load Customers.
(b) The sum of all Firm and non-firm Point-To-Point Transmission
Service provided to the Transmission Customer at any time pursuant to
this section shall not exceed the Reserved Capacity in the relevant
Service Agreement under which such services are provided.
(c) The Transmission Customer shall retain its right to schedule
Firm Point-To-Point Transmission Service at the Receipt and Delivery
Points specified in the relevant Service Agreement in the amount of its
original capacity reservation.
(d) Service over Secondary Receipt and Delivery Points on a non-
firm basis shall not require the filing of an Application for Non-Firm
Point-To-Point Transmission Service under the Tariff. However, all
other requirements of Part II of the Tariff (except as to transmission
rates) shall apply to transmission service on a non-firm basis over
Secondary Receipt and Delivery Points.
22.2 Modification on a Firm Basis
Any request by a Transmission Customer to modify Receipt and
Delivery Points on a firm basis shall be treated as a new request for
service in accordance with Section 17 hereof, except that such
Transmission Customer shall not be obligated to pay any additional
deposit if the capacity reservation does not exceed the amount reserved
in the existing Service Agreement. While such new request is pending,
the Transmission Customer shall retain its priority for service at the
existing firm Receipt and Delivery Points specified in its Service
Agreement.
23 Sale or Assignment of Transmission Service
23.1 Procedures for Assignment or Transfer of Service
Subject to Commission approval of any necessary filings, a
Transmission Customer may sell, assign, or transfer all or a portion of
its rights under its Service Agreement, but only to another Eligible
Customer (the Assignee). The Transmission Customer that sells, assigns
or transfers its rights under its Service Agreement is hereafter
referred to as the Reseller. Compensation to Resellers shall not exceed
the higher of (i) the original rate paid by the Reseller, (ii) the
Transmission Provider's maximum rate on file at the time of the
assignment, or (iii) the Reseller's opportunity cost capped at the
Transmission Provider's cost of expansion; provided that, for service
prior to October 1, 2010, compensation to Resellers shall be at rates
established by agreement between the Reseller and the Assignee.
The Assignee must execute a service agreement with the Transmission
Provider governing reassignments of transmission service prior to the
date on which the reassigned service commences. The Transmission
Provider shall charge the Reseller, as appropriate, at the rate stated
in the Reseller's Service Agreement with the Transmission Provider or
the associated OASIS schedule and credit the Reseller with the price
reflected in the Assignee's Service Agreement with the Transmission
Provider or the associated OASIS schedule; provided that, such credit
shall be reversed in the event of non-payment by the Assignee. If the
Assignee does not request any change in the Point(s) of Receipt or the
Point(s) of Delivery, or a change in any other term or condition set
forth in the original Service Agreement, the Assignee will receive the
same services as did the Reseller and the priority of service for the
Assignee will be the same as that of the Reseller. The Assignee will be
subject to all terms and conditions of this Tariff. If the Assignee
requests a change in service, the reservation priority of service will
be determined by the Transmission Provider pursuant to Section 13.2.
23.2 Limitations on Assignment or Transfer of Service
If the Assignee requests a change in the Point(s) of Receipt or
Point(s) of Delivery, or a change in any other specifications set forth
in the original Service Agreement, the Transmission Provider will
consent to such change subject to the provisions of the Tariff,
provided that the change will not impair the operation and reliability
of the Transmission Provider's generation, transmission, or
distribution systems. The Assignee shall compensate the Transmission
Provider for performing any System Impact Study needed to evaluate the
capability of the Transmission System to accommodate the proposed
change and any additional costs resulting from such change. The
Reseller shall remain liable for the performance of all obligations
under the Service Agreement, except as specifically agreed to by the
Transmission Provider and the Reseller through an amendment to the
Service Agreement.
23.3 Information on Assignment or Transfer of Service
In accordance with Section 4, all sales or assignments of capacity
must be conducted through or otherwise posted on the Transmission
Provider's OASIS on or before the date the reassigned service commences
and are subject to Section 23.1. Resellers may also use the
Transmission Provider's OASIS to post transmission capacity available
for resale.
24 Metering and Power Factor Correction at Receipt and Delivery
Points(s)
24.1 Transmission Customer Obligations
Unless otherwise agreed, the Transmission Customer shall be
responsible for installing and maintaining compatible metering and
communications equipment to accurately account for the capacity and
energy being transmitted under Part II of the Tariff and to communicate
the information to the Transmission Provider. Such equipment shall
remain the property of the Transmission Customer.
24.2 Transmission Provider Access to Metering Data
The Transmission Provider shall have access to metering data, which
may reasonably be required to facilitate measurements and billing under
the Service Agreement.
24.3 Power Factor
Unless otherwise agreed, the Transmission Customer is required to
maintain a power factor within the same range as the Transmission
Provider pursuant to Good Utility Practices. The power factor
requirements are specified in the Service Agreement where applicable.
25 Compensation for Transmission Service
Rates for Firm and Non-Firm Point-To-Point Transmission Service are
provided in the Schedules appended to the Tariff: Firm Point-To-Point
Transmission Service (Schedule 7); and Non-Firm Point-To-Point
Transmission Service (Schedule 8). The Transmission Provider shall use
Part II of the Tariff to make its Third-Party Sales. The Transmission
Provider shall account for such use at the applicable Tariff rates,
pursuant to Section 8.
26 Stranded Cost Recovery
The Transmission Provider may seek to recover stranded costs from
the Transmission Customer pursuant to this
[[Page 3131]]
Tariff in accordance with the terms, conditions and procedures set
forth in FERC Order No. 888. However, the Transmission Provider must
separately file any specific proposed stranded cost charge under
Section 205 of the Federal Power Act.
27 Compensation for New Facilities and Redispatch Costs
Whenever a System Impact Study performed by the Transmission
Provider in connection with the provision of Firm Point-To-Point
Transmission Service identifies the need for new facilities, the
Transmission Customer shall be responsible for such costs to the extent
consistent with Commission policy. Whenever a System Impact Study
performed by the Transmission Provider identifies capacity constraints
that may be relieved by redispatching the Transmission Provider's
resources to eliminate such constraints, the Transmission Customer
shall be responsible for the redispatch costs to the extent consistent
with Commission policy.
III. Network Integration Transmission Service
Preamble
The Transmission Provider will provide Network Integration
Transmission Service pursuant to the applicable terms and conditions
contained in the Tariff and Service Agreement. Network Integration
Transmission Service allows the Network Customer to integrate,
economically dispatch and regulate its current and planned Network
Resources to serve its Network Load in a manner comparable to that in
which the Transmission Provider utilizes its Transmission System to
serve its Native Load Customers. Network Integration Transmission
Service also may be used by the Network Customer to deliver economy
energy purchases to its Network Load from non-designated resources on
an as-available basis without additional charge. Transmission service
for sales to non-designated loads will be provided pursuant to the
applicable terms and conditions of Part II of the Tariff.
28 Nature of Network Integration Transmission Service
28.1 Scope of Service
Network Integration Transmission Service is a transmission service
that allows Network Customers to efficiently and economically utilize
their Network Resources (as well as other non-designated generation
resources) to serve their Network Load located in the Transmission
Provider's Control Area and any additional load that may be designated
pursuant to Section 31.3 of the Tariff. The Network Customer taking
Network Integration Transmission Service must obtain or provide
Ancillary Services pursuant to Section 3.
28.2 Transmission Provider Responsibilities
The Transmission Provider will plan, construct, operate and
maintain its Transmission System in accordance with Good Utility
Practice and its planning obligations in Attachment K in order to
provide the Network Customer with Network Integration Transmission
Service over the Transmission Provider's Transmission System. The
Transmission Provider, on behalf of its Native Load Customers, shall be
required to designate resources and loads in the same manner as any
Network Customer under Part III of this Tariff. This information must
be consistent with the information used by the Transmission Provider to
calculate available transfer capability. The Transmission Provider
shall include the Network Customer's Network Load in its Transmission
System planning and shall, consistent with Good Utility Practice and
Attachment K, endeavor to construct and place into service sufficient
transfer capability to deliver the Network Customer's Network Resources
to serve its Network Load on a basis comparable to the Transmission
Provider's delivery of its own generating and purchased resources to
its Native Load Customers.
28.3 Network Integration Transmission Service
The Transmission Provider will provide firm transmission service
over its Transmission System to the Network Customer for the delivery
of capacity and energy from its designated Network Resources to service
its Network Loads on a basis that is comparable to the Transmission
Provider's use of the Transmission System to reliably serve its Native
Load Customers.
28.4 Secondary Service
The Network Customer may use the Transmission Provider's
Transmission System to deliver energy to its Network Loads from
resources that have not been designated as Network Resources. Such
energy shall be transmitted, on an as-available basis, at no additional
charge. Secondary service shall not require the filing of an
Application for Network Integration Transmission Service under the
Tariff. However, all other requirements of Part III of the Tariff
(except for transmission rates) shall apply to secondary service.
Deliveries from resources other than Network Resources will have a
higher priority than any Non-Firm Point-To-Point Transmission Service
under Part II of the Tariff.
28.5 Real Power Losses
Real Power Losses are associated with all transmission service. The
Transmission Provider is not obligated to provide Real Power Losses.
The Network Customer is responsible for replacing losses associated
with all transmission service as calculated by the Transmission
Provider. The applicable Real Power Loss factors are as follows: [To be
completed by the Transmission Provider].
28.6 Restrictions on Use of Service
The Network Customer shall not use Network Integration Transmission
Service for (i) sales of capacity and energy to non-designated loads,
or (ii) direct or indirect provision of transmission service by the
Network Customer to third parties. All Network Customers taking Network
Integration Transmission Service shall use Point-to-Point Transmission
Service under Part II of the Tariff for any Third-Party Sale which
requires use of the Transmission Provider's Transmission System. The
Transmission Provider shall specify any appropriate charges and
penalties and all related terms and conditions applicable in the event
that a Network Customer uses Network Integration Transmission Service
or secondary service pursuant to Section 28.4 to facilitate a wholesale
sale that does not serve a Network Load.
29 Initiating Service
29.1 Condition Precedent for Receiving Service
Subject to the terms and conditions of Part III of the Tariff, the
Transmission Provider will provide Network Integration Transmission
Service to any Eligible Customer, provided that (i) the Eligible
Customer completes an Application for service as provided under Part
III of the Tariff, (ii) the Eligible Customer and the Transmission
Provider complete the technical arrangements set forth in Sections 29.3
and 29.4, (iii) the Eligible Customer executes a Service Agreement
pursuant to Attachment F for service under Part III of the Tariff or
requests in writing that the Transmission Provider file a proposed
unexecuted Service Agreement with the Commission, and (iv) the Eligible
Customer executes a Network Operating Agreement with the
[[Page 3132]]
Transmission Provider pursuant to Attachment G, or requests in writing
that the Transmission Provider file a proposed unexecuted Network
Operating Agreement.
29.2 Application Procedures
An Eligible Customer requesting service under Part III of the
Tariff must submit an Application, with a deposit approximating the
charge for one month of service, to the Transmission Provider as far as
possible in advance of the month in which service is to commence.
Unless subject to the procedures in Section 2, Completed Applications
for Network Integration Transmission Service will be assigned a
priority according to the date and time the Application is received,
with the earliest Application receiving the highest priority.
Applications should be submitted by entering the information listed
below on the Transmission Provider's OASIS. Prior to implementation of
the Transmission Provider's OASIS, a Completed Application may be
submitted by (i) transmitting the required information to the
Transmission Provider by telefax, or (ii) providing the information by
telephone over the Transmission Provider's time recorded telephone
line. Each of these methods will provide a time-stamped record for
establishing the service priority of the Application. A Completed
Application shall provide all of the information included in 18 CFR
Sec. 2.20 including but not limited to the following:
(i) The identity, address, telephone number and facsimile number of
the party requesting service;
(ii) A statement that the party requesting service is, or will be
upon commencement of service, an Eligible Customer under the Tariff;
(iii) A description of the Network Load at each delivery point.
This description should separately identify and provide the Eligible
Customer's best estimate of the total loads to be served at each
transmission voltage level, and the loads to be served from each
Transmission Provider substation at the same transmission voltage
level. The description should include a ten (10) year forecast of
summer and winter load and resource requirements beginning with the
first year after the service is scheduled to commence;
(iv) The amount and location of any interruptible loads included in
the Network Load. This shall include the summer and winter capacity
requirements for each interruptible load (had such load not been
interruptible), that portion of the load subject to interruption, the
conditions under which an interruption can be implemented and any
limitations on the amount and frequency of interruptions. An Eligible
Customer should identify the amount of interruptible customer load (if
any) included in the 10 year load forecast provided in response to
(iii) above;
(v) A description of Network Resources (current and 10-year
projection). For each on-system Network Resource, such description
shall include:
Unit size and amount of capacity from that unit to be
designated as Network Resource
VAR capability (both leading and lagging) of all
generators
Operating restrictions
--Any periods of restricted operations throughout the year
--Maintenance schedules
--Minimum loading level of unit
--Normal operating level of unit
--Any must-run unit designations required for system reliability or
contract reasons
Approximate variable generating cost ($/MWH) for
redispatch computations
Arrangements governing sale and delivery of power to third
parties from generating facilities located in the Transmission Provider
Control Area, where only a portion of unit output is designated as a
Network Resource;
For each off-system Network Resource, such description shall
include:
Identification of the Network Resource as an off-system
resource
Amount of power to which the customer has rights
Identification of the control area from which the power
will originate
Delivery point(s) to the Transmission Provider's
Transmission System
Transmission arrangements on the external transmission
system(s)
Operating restrictions, if any
--Any periods of restricted operations throughout the year
--Maintenance schedules
--Minimum loading level of unit
--Normal operating level of unit
--Any must-run unit designations required for system reliability or
contract reasons
Approximate variable generating cost ($/MWH) for
redispatch computations;
(vi) Description of Eligible Customer's transmission system:
Load flow and stability data, such as real and reactive
parts of the load, lines, transformers, reactive devices and load type,
including normal and emergency ratings of all transmission equipment in
a load flow format compatible with that used by the Transmission
Provider
Operating restrictions needed for reliability
Operating guides employed by system operators
Contractual restrictions or committed uses of the Eligible
Customer's transmission system, other than the Eligible Customer's
Network Loads and Resources
Location of Network Resources described in subsection (v)
above
10 year projection of system expansions or upgrades
Transmission System maps that include any proposed
expansions or upgrades
Thermal ratings of Eligible Customer's Control Area ties
with other Control Areas;
(vii) Service Commencement Date and the term of the requested
Network Integration Transmission Service. The minimum term for Network
Integration Transmission Service is one year;
(viii) A statement signed by an authorized officer from or agent of
the Network Customer attesting that all of the network resources listed
pursuant to Section 29.2(v) satisfy the following conditions: (1) The
Network Customer owns the resource, has committed to purchase
generation pursuant to an executed contract, or has committed to
purchase generation where execution of a contract is contingent upon
the availability of transmission service under Part III of the Tariff;
and (2) the Network Resources do not include any resources, or any
portion thereof, that are committed for sale to non-designated third
party load or otherwise cannot be called upon to meet the Network
Customer's Network Load on a non-interruptible basis; and
(ix) Any additional information required of the Transmission
Customer as specified in the Transmission Provider's planning process
established in Attachment K.
Unless the Parties agree to a different time frame, the
Transmission Provider must acknowledge the request within ten (10) days
of receipt. The acknowledgement must include a date by which a
response, including a Service Agreement, will be sent to the Eligible
Customer. If an Application fails to meet the requirements of this
section, the Transmission Provider shall notify the Eligible Customer
requesting service within fifteen (15) days of receipt and specify the
reasons for such failure. Wherever possible, the Transmission Provider
will attempt to remedy deficiencies in the Application
[[Continued on page 3133]]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]
[[pp. 3133-3143]] Preventing Undue Discrimination and Preference in Transmission
Service
[[Continued from page 3132]]
[[Page 3133]]
through informal communications with the Eligible Customer. If such
efforts are unsuccessful, the Transmission Provider shall return the
Application without prejudice to the Eligible Customer filing a new or
revised Application that fully complies with the requirements of this
section. The Eligible Customer will be assigned a new priority
consistent with the date of the new or revised Application. The
Transmission Provider shall treat this information consistent with the
standards of conduct contained in Part 37 of the Commission's
regulations.
29.3 Technical Arrangements To Be Completed Prior to Commencement of
Service
Network Integration Transmission Service shall not commence until
the Transmission Provider and the Network Customer, or a third party,
have completed installation of all equipment specified under the
Network Operating Agreement consistent with Good Utility Practice and
any additional requirements reasonably and consistently imposed to
ensure the reliable operation of the Transmission System. The
Transmission Provider shall exercise reasonable efforts, in
coordination with the Network Customer, to complete such arrangements
as soon as practicable taking into consideration the Service
Commencement Date.
29.4 Network Customer Facilities
The provision of Network Integration Transmission Service shall be
conditioned upon the Network Customer's constructing, maintaining and
operating the facilities on its side of each delivery point or
interconnection necessary to reliably deliver capacity and energy from
the Transmission Provider's Transmission System to the Network
Customer. The Network Customer shall be solely responsible for
constructing or installing all facilities on the Network Customer's
side of each such delivery point or interconnection.
29.5 Filing of Service Agreement
The Transmission Provider will file Service Agreements with the
Commission in compliance with applicable Commission regulations.
30 Network Resources
30.1 Designation of Network Resources
Network Resources shall include all generation owned, purchased or
leased by the Network Customer designated to serve Network Load under
the Tariff. Network Resources may not include resources, or any portion
thereof, that are committed for sale to non-designated third party load
or otherwise cannot be called upon to meet the Network Customer's
Network Load on a non-interruptible basis. Any owned or purchased
resources that were serving the Network Customer's loads under firm
agreements entered into on or before the Service Commencement Date
shall initially be designated as Network Resources until the Network
Customer terminates the designation of such resources.
30.2 Designation of New Network Resources
The Network Customer may designate a new Network Resource by
providing the Transmission Provider with as much advance notice as
practicable. A designation of a new Network Resource must be made
through the Transmission Provider's OASIS by a request for modification
of service pursuant to an Application under Section 29. This request
must include a statement that the new network resource satisfies the
following conditions: (1) The Network Customer owns the resource, has
committed to purchase generation pursuant to an executed contract, or
has committed to purchase generation where execution of a contract is
contingent upon the availability of transmission service under Part III
of the Tariff; and (2) The Network Resources do not include any
resources, or any portion thereof, that are committed for sale to non-
designated third party load or otherwise cannot be called upon to meet
the Network Customer's Network Load on a non-interruptible basis. The
Network Customer's request will be deemed deficient if it does not
include this statement and the Transmission Provider will follow the
procedures for a deficient application as described in Section 29.2 of
the Tariff.
30.3 Termination of Network Resources
The Network Customer may terminate the designation of all or part
of a generating resource as a Network Resource by providing
notification to the Transmission Provider through OASIS as soon as
reasonably practicable, but not later than the firm scheduling deadline
for the period of termination. Any request for termination of Network
Resource status must be submitted on OASIS, and should indicate whether
the request is for indefinite or temporary termination. A request for
indefinite termination of Network Resource status must indicate the
date and time that the termination is to be effective, and the
identification and capacity of the resource(s) or portions thereof to
be indefinitely terminated. A request for temporary termination of
Network Resource status must include the following:
(i) Effective date and time of temporary termination;
(ii) Effective date and time of redesignation, following period of
temporary termination;
(iii) Identification and capacity of resource(s) or portions
thereof to be temporarily terminated;
(iv) Resource description and attestation for redesignating the
network resource following the temporary termination, in accordance
with Section 30.2; and
(v) Identification of any related transmission service requests to
be evaluated concomitantly with the request for temporary termination,
such that the requests for undesignation and the request for these
related transmission service requests must be approved or denied as a
single request. The evaluation of these related transmission service
requests must take into account the termination of the network
resources identified in (iii) above, as well as all competing
transmission service requests of higher priority.
As part of a temporary termination, a Network Customer may only
redesignate the same resource that was originally designated, or a
portion thereof. Requests to redesignate a different resource and/or a
resource with increased capacity will be deemed deficient and the
Transmission Provider will follow the procedures for a deficient
application as described in Section 29.2 of the Tariff.
30.4 Operation of Network Resources
The Network Customer shall not operate its designated Network
Resources located in the Network Customer's or Transmission Provider's
Control Area such that the output of those facilities exceeds its
designated Network Load, plus Non-Firm Sales delivered pursuant to Part
II of the Tariff, plus losses, plus power sales under a Commission-
approved reserve sharing program. This limitation shall not apply to
changes in the operation of a Transmission Customer's Network Resources
at the request of the Transmission Provider to respond to an emergency
or other unforeseen condition which may impair or degrade the
reliability of the Transmission System. For all Network Resources not
physically connected with the Transmission Provider's Transmission
System, the Network Customer may not schedule delivery of energy in
excess of the Network Resource's capacity, as specified in the Network
Customer's
[[Page 3134]]
Application pursuant to Section 29, unless the Network Customer
supports such delivery within the Transmission Provider's Transmission
System by either obtaining Point-to-Point Transmission Service or
utilizing secondary service pursuant to Section 28.4. The Transmission
Provider shall specify the rate treatment and all related terms and
conditions applicable in the event that a Network Customer's schedule
at the delivery point for a Network Resource not physically
interconnected with the Transmission Provider's Transmission System
exceeds the Network Resource's designated capacity, excluding energy
delivered using secondary service or Point-to-Point Transmission
Service.
30.5 Network Customer Redispatch Obligation
As a condition to receiving Network Integration Transmission
Service, the Network Customer agrees to redispatch its Network
Resources as requested by the Transmission Provider pursuant to Section
33.2. To the extent practical, the redispatch of resources pursuant to
this section shall be on a least cost, non-discriminatory basis between
all Network Customers, and the Transmission Provider.
30.6 Transmission Arrangements for Network Resources Not Physically
Interconnected With the Transmission Provider
The Network Customer shall be responsible for any arrangements
necessary to deliver capacity and energy from a Network Resource not
physically interconnected with the Transmission Provider's Transmission
System. The Transmission Provider will undertake reasonable efforts to
assist the Network Customer in obtaining such arrangements, including
without limitation, providing any information or data required by such
other entity pursuant to Good Utility Practice.
30.7 Limitation on Designation of Network Resources
The Network Customer must demonstrate that it owns or has committed
to purchase generation pursuant to an executed contract in order to
designate a generating resource as a Network Resource. Alternatively,
the Network Customer may establish that execution of a contract is
contingent upon the availability of transmission service under Part III
of the Tariff.
30.8 Use of Interface Capacity by the Network Customer
There is no limitation upon a Network Customer's use of the
Transmission Provider's Transmission System at any particular interface
to integrate the Network Customer's Network Resources (or substitute
economy purchases) with its Network Loads. However, a Network
Customer's use of the Transmission Provider's total interface capacity
with other transmission systems may not exceed the Network Customer's
Load.
30.9 Network Customer Owned Transmission Facilities
The Network Customer that owns existing transmission facilities
that are integrated with the Transmission Provider's Transmission
System may be eligible to receive consideration either through a
billing credit or some other mechanism. In order to receive such
consideration the Network Customer must demonstrate that its
transmission facilities are integrated into the plans or operations of
the Transmission Provider, to serve its power and transmission
customers. For facilities added by the Network Customer subsequent to
the [the effective date of a Final Rule in RM05-25-000], the Network
Customer shall receive credit for such transmission facilities added if
such facilities are integrated into the operations of the Transmission
Provider's facilities; provided however, the Network Customer's
transmission facilities shall be presumed to be integrated if such
transmission facilities, if owned by the Transmission Provider, would
be eligible for inclusion in the Transmission Provider's annual
transmission revenue requirement as specified in Attachment H.
Calculation of any credit under this subsection shall be addressed in
either the Network Customer's Service Agreement or any other agreement
between the Parties.
31 Designation of Network Load
31.1 Network Load
The Network Customer must designate the individual Network Loads on
whose behalf the Transmission Provider will provide Network Integration
Transmission Service. The Network Loads shall be specified in the
Service Agreement.
31.2 New Network Loads Connected With the Transmission Provider
The Network Customer shall provide the Transmission Provider with
as much advance notice as reasonably practicable of the designation of
new Network Load that will be added to its Transmission System. A
designation of new Network Load must be made through a modification of
service pursuant to a new Application. The Transmission Provider will
use due diligence to install any transmission facilities required to
interconnect a new Network Load designated by the Network Customer. The
costs of new facilities required to interconnect a new Network Load
shall be determined in accordance with the procedures provided in
Section 32.4 and shall be charged to the Network Customer in accordance
with Commission policies.
31.3 Network Load Not Physically Interconnected With the Transmission
Provider
This section applies to both initial designation pursuant to
Section 31.1 and the subsequent addition of new Network Load not
physically interconnected with the Transmission Provider. To the extent
that the Network Customer desires to obtain transmission service for a
load outside the Transmission Provider's Transmission System, the
Network Customer shall have the option of (1) electing to include the
entire load as Network Load for all purposes under Part III of the
Tariff and designating Network Resources in connection with such
additional Network Load, or (2) excluding that entire load from its
Network Load and purchasing Point-To-Point Transmission Service under
Part II of the Tariff. To the extent that the Network Customer gives
notice of its intent to add a new Network Load as part of its Network
Load pursuant to this section the request must be made through a
modification of service pursuant to a new Application.
31.4 New Interconnection Points
To the extent the Network Customer desires to add a new Delivery
Point or interconnection point between the Transmission Provider's
Transmission System and a Network Load, the Network Customer shall
provide the Transmission Provider with as much advance notice as
reasonably practicable.
31.5 Changes in Service Requests
Under no circumstances shall the Network Customer's decision to
cancel or delay a requested change in Network Integration Transmission
Service (e.g. the addition of a new Network Resource or designation of
a new Network Load) in any way relieve the Network Customer of its
obligation to pay the costs of transmission facilities constructed by
the Transmission Provider and charged to the Network Customer as
reflected in the Service
[[Page 3135]]
Agreement. However, the Transmission Provider must treat any requested
change in Network Integration Transmission Service in a non-
discriminatory manner.
31.6 Annual Load and Resource Information Updates
The Network Customer shall provide the Transmission Provider with
annual updates of Network Load and Network Resource forecasts
consistent with those included in its Application for Network
Integration Transmission Service under Part III of the Tariff
including, but not limited to, any information provided under section
29.2(ix) pursuant to the Transmission Provider's planning process in
Attachment K. The Network Customer also shall provide the Transmission
Provider with timely written notice of material changes in any other
information provided in its Application relating to the Network
Customer's Network Load, Network Resources, its transmission system or
other aspects of its facilities or operations affecting the
Transmission Provider's ability to provide reliable service.
32 Additional Study Procedures for Network Integration Transmission
Service Requests
32.1 Notice of Need for System Impact Study
After receiving a request for service, the Transmission Provider
shall determine on a non-discriminatory basis whether a System Impact
Study is needed. A description of the Transmission Provider's
methodology for completing a System Impact Study is provided in
Attachment D. If the Transmission Provider determines that a System
Impact Study is necessary to accommodate the requested service, it
shall so inform the Eligible Customer, as soon as practicable. In such
cases, the Transmission Provider shall within thirty (30) days of
receipt of a Completed Application, tender a System Impact Study
Agreement pursuant to which the Eligible Customer shall agree to
reimburse the Transmission Provider for performing the required System
Impact Study. For a service request to remain a Completed Application,
the Eligible Customer shall execute the System Impact Study Agreement
and return it to the Transmission Provider within fifteen (15) days. If
the Eligible Customer elects not to execute the System Impact Study
Agreement, its Application shall be deemed withdrawn and its deposit
shall be returned with interest.
32.2 System Impact Study Agreement and Cost Reimbursement
(i) The System Impact Study Agreement will clearly specify the
Transmission Provider's estimate of the actual cost, and time for
completion of the System Impact Study. The charge shall not exceed the
actual cost of the study. In performing the System Impact Study, the
Transmission Provider shall rely, to the extent reasonably practicable,
on existing transmission planning studies. The Eligible Customer will
not be assessed a charge for such existing studies; however, the
Eligible Customer will be responsible for charges associated with any
modifications to existing planning studies that are reasonably
necessary to evaluate the impact of the Eligible Customer's request for
service on the Transmission System.
(ii) If in response to multiple Eligible Customers requesting
service in relation to the same competitive solicitation, a single
System Impact Study is sufficient for the Transmission Provider to
accommodate the service requests, the costs of that study shall be pro-
rated among the Eligible Customers.
(iii) For System Impact Studies that the Transmission Provider
conducts on its own behalf, the Transmission Provider shall record the
cost of the System Impact Studies pursuant to Section 8.
32.3 System Impact Study Procedures
Upon receipt of an executed System Impact Study Agreement, the
Transmission Provider will use due diligence to complete the required
System Impact Study within a sixty (60) day period. The System Impact
Study shall identify (1) any system constraints, identified with
specificity by transmission element or flowgate, (2) redispatch options
(when requested by an Eligible Customer) including, to the extent
possible, an estimate of the cost of redispatch, (3) available options
for installation of automatic devices to curtail service (when
requested by an Eligible Customer), and (4) additional Direct
Assignment Facilities or Network Upgrades required to provide the
requested service. For customers requesting the study of redispatch
options, the System Impact Study shall (1) identify all resources
located within the Transmission Provider's Control Area that can
significantly contribute toward relieving the system constraint and (2)
provide a measurement of each resource's impact on the system
constraint. If the Transmission Provider possesses information
indicating that any resource outside its Control Area could relieve the
constraint, it shall identify each such resource in the System Impact
Study. In the event that the Transmission Provider is unable to
complete the required System Impact Study within such time period, it
shall so notify the Eligible Customer and provide an estimated
completion date along with an explanation of the reasons why additional
time is required to complete the required studies. A copy of the
completed System Impact Study and related work papers shall be made
available to the Eligible Customer as soon as the System Impact Study
is complete. The Transmission Provider will use the same due diligence
in completing the System Impact Study for an Eligible Customer as it
uses when completing studies for itself. The Transmission Provider
shall notify the Eligible Customer immediately upon completion of the
System Impact Study if the Transmission System will be adequate to
accommodate all or part of a request for service or that no costs are
likely to be incurred for new transmission facilities or upgrades. In
order for a request to remain a Completed Application, within fifteen
(15) days of completion of the System Impact Study the Eligible
Customer must execute a Service Agreement or request the filing of an
unexecuted Service Agreement, or the Application shall be deemed
terminated and withdrawn.
32.4 Facilities Study Procedures
If a System Impact Study indicates that additions or upgrades to
the Transmission System are needed to supply the Eligible Customer's
service request, the Transmission Provider, within thirty (30) days of
the completion of the System Impact Study, shall tender to the Eligible
Customer a Facilities Study Agreement pursuant to which the Eligible
Customer shall agree to reimburse the Transmission Provider for
performing the required Facilities Study. For a service request to
remain a Completed Application, the Eligible Customer shall execute the
Facilities Study Agreement and return it to the Transmission Provider
within fifteen (15) days. If the Eligible Customer elects not to
execute the Facilities Study Agreement, its Application shall be deemed
withdrawn and its deposit shall be returned with interest. Upon receipt
of an executed Facilities Study Agreement, the Transmission Provider
will use due diligence to complete the required Facilities Study within
a sixty (60) day period. If the Transmission Provider is unable to
complete the Facilities Study in the allotted time period, the
Transmission Provider shall
[[Page 3136]]
notify the Eligible Customer and provide an estimate of the time needed
to reach a final determination along with an explanation of the reasons
that additional time is required to complete the study. When completed,
the Facilities Study will include a good faith estimate of (i) the cost
of Direct Assignment Facilities to be charged to the Eligible Customer,
(ii) the Eligible Customer's appropriate share of the cost of any
required Network Upgrades, and (iii) the time required to complete such
construction and initiate the requested service. The Eligible Customer
shall provide the Transmission Provider with a letter of credit or
other reasonable form of security acceptable to the Transmission
Provider equivalent to the costs of new facilities or upgrades
consistent with commercial practices as established by the Uniform
Commercial Code. The Eligible Customer shall have thirty (30) days to
execute a Service Agreement or request the filing of an unexecuted
Service Agreement and provide the required letter of credit or other
form of security or the request no longer will be a Completed
Application and shall be deemed terminated and withdrawn.
32.5 Penalties for Failure To Meet Study Deadlines
Section 19.9 defines penalties that apply for failure to meet the
60-day study completion due diligence deadlines for System Impact
Studies and Facilities Studies under Part II of the Tariff. These same
requirements and penalties apply to service under Part III of the
Tariff.
33 Load Shedding and Curtailments
33.1 Procedures
Prior to the Service Commencement Date, the Transmission Provider
and the Network Customer shall establish Load Shedding and Curtailment
procedures pursuant to the Network Operating Agreement with the
objective of responding to contingencies on the Transmission System and
on systems directly and indirectly interconnected with Transmission
Provider's Transmission System. The Parties will implement such
programs during any period when the Transmission Provider determines
that a system contingency exists and such procedures are necessary to
alleviate such contingency. The Transmission Provider will notify all
affected Network Customers in a timely manner of any scheduled
Curtailment.
33.2 Transmission Constraints
During any period when the Transmission Provider determines that a
transmission constraint exists on the Transmission System, and such
constraint may impair the reliability of the Transmission Provider's
system, the Transmission Provider will take whatever actions,
consistent with Good Utility Practice, that are reasonably necessary to
maintain the reliability of the Transmission Provider's system. To the
extent the Transmission Provider determines that the reliability of the
Transmission System can be maintained by redispatching resources, the
Transmission Provider will initiate procedures pursuant to the Network
Operating Agreement to redispatch all Network Resources and the
Transmission Provider's own resources on a least-cost basis without
regard to the ownership of such resources. Any redispatch under this
section may not unduly discriminate between the Transmission Provider's
use of the Transmission System on behalf of its Native Load Customers
and any Network Customer's use of the Transmission System to serve its
designated Network Load.
33.3 Cost Responsibility for Relieving Transmission Constraints
Whenever the Transmission Provider implements least-cost redispatch
procedures in response to a transmission constraint, the Transmission
Provider and Network Customers will each bear a proportionate share of
the total redispatch cost based on their respective Load Ratio Shares.
33.4 Curtailments of Scheduled Deliveries
If a transmission constraint on the Transmission Provider's
Transmission System cannot be relieved through the implementation of
least-cost redispatch procedures and the Transmission Provider
determines that it is necessary to Curtail scheduled deliveries, the
Parties shall Curtail such schedules in accordance with the Network
Operating Agreement or pursuant to the Transmission Loading Relief
procedures specified in Attachment J.
33.5 Allocation of Curtailments
The Transmission Provider shall, on a non-discriminatory basis,
Curtail the transaction(s) that effectively relieve the constraint.
However, to the extent practicable and consistent with Good Utility
Practice, any Curtailment will be shared by the Transmission Provider
and Network Customer in proportion to their respective Load Ratio
Shares. The Transmission Provider shall not direct the Network Customer
to Curtail schedules to an extent greater than the Transmission
Provider would Curtail the Transmission Provider's schedules under
similar circumstances.
33.6 Load Shedding
To the extent that a system contingency exists on the Transmission
Provider's Transmission System and the Transmission Provider determines
that it is necessary for the Transmission Provider and the Network
Customer to shed load, the Parties shall shed load in accordance with
previously established procedures under the Network Operating
Agreement.
33.7 System Reliability
Notwithstanding any other provisions of this Tariff, the
Transmission Provider reserves the right, consistent with Good Utility
Practice and on a not unduly discriminatory basis, to Curtail Network
Integration Transmission Service without liability on the Transmission
Provider's part for the purpose of making necessary adjustments to,
changes in, or repairs on its lines, substations and facilities, and in
cases where the continuance of Network Integration Transmission Service
would endanger persons or property. In the event of any adverse
condition(s) or disturbance(s) on the Transmission Provider's
Transmission System or on any other system(s) directly or indirectly
interconnected with the Transmission Provider's Transmission System,
the Transmission Provider, consistent with Good Utility Practice, also
may Curtail Network Integration Transmission Service in order to (i)
limit the extent or damage of the adverse condition(s) or
disturbance(s), (ii) prevent damage to generating or transmission
facilities, or (iii) expedite restoration of service. The Transmission
Provider will give the Network Customer as much advance notice as is
practicable in the event of such Curtailment. Any Curtailment of
Network Integration Transmission Service will be not unduly
discriminatory relative to the Transmission Provider's use of the
Transmission System on behalf of its Native Load Customers. The
Transmission Provider shall specify the rate treatment and all related
terms and conditions applicable in the event that the Network Customer
fails to respond to established Load Shedding and Curtailment
procedures.
34 Rates and Charges
The Network Customer shall pay the Transmission Provider for any
Direct
[[Page 3137]]
Assignment Facilities, Ancillary Services, and applicable study costs,
consistent with Commission policy, along with the following:
34.1 Monthly Demand Charge
The Network Customer shall pay a monthly Demand Charge, which shall
be determined by multiplying its Load Ratio Share times one twelfth (1/
12) of the Transmission Provider's Annual Transmission Revenue
Requirement specified in Schedule H.
34.2 Determination of Network Customer's Monthly Network Load
The Network Customer's monthly Network Load is its hourly load
(including its designated Network Load not physically interconnected
with the Transmission Provider under Section 31.3) coincident with the
Transmission Provider's Monthly Transmission System Peak.
34.3 Determination of Transmission Provider's Monthly Transmission
System Load
The Transmission Provider's monthly Transmission System load is the
Transmission Provider's Monthly Transmission System Peak minus the
coincident peak usage of all Firm Point-To-Point Transmission Service
customers pursuant to Part II of this Tariff plus the Reserved Capacity
of all Firm Point-To-Point Transmission Service customers.
34.4 Redispatch Charge
The Network Customer shall pay a Load Ratio Share of any redispatch
costs allocated between the Network Customer and the Transmission
Provider pursuant to Section 33. To the extent that the Transmission
Provider incurs an obligation to the Network Customer for redispatch
costs in accordance with Section 33, such amounts shall be credited
against the Network Customer's bill for the applicable month.
34.5 Stranded Cost Recovery
The Transmission Provider may seek to recover stranded costs from
the Network Customer pursuant to this Tariff in accordance with the
terms, conditions and procedures set forth in FERC Order No. 888.
However, the Transmission Provider must separately file any proposal to
recover stranded costs under Section 205 of the Federal Power Act.
35 Operating Arrangements
35.1 Operation Under the Network Operating Agreement
The Network Customer shall plan, construct, operate and maintain
its facilities in accordance with Good Utility Practice and in
conformance with the Network Operating Agreement.
35.2 Network Operating Agreement
The terms and conditions under which the Network Customer shall
operate its facilities and the technical and operational matters
associated with the implementation of Part III of the Tariff shall be
specified in the Network Operating Agreement. The Network Operating
Agreement shall provide for the Parties to (i) operate and maintain
equipment necessary for integrating the Network Customer within the
Transmission Provider's Transmission System (including, but not limited
to, remote terminal units, metering, communications equipment and
relaying equipment), (ii) transfer data between the Transmission
Provider and the Network Customer (including, but not limited to, heat
rates and operational characteristics of Network Resources, generation
schedules for units outside the Transmission Provider's Transmission
System, interchange schedules, unit outputs for redispatch required
under Section 33, voltage schedules, loss factors and other real time
data), (iii) use software programs required for data links and
constraint dispatching, (iv) exchange data on forecasted loads and
resources necessary for long-term planning, and (v) address any other
technical and operational considerations required for implementation of
Part III of the Tariff, including scheduling protocols. The Network
Operating Agreement will recognize that the Network Customer shall
either (i) operate as a Control Area under applicable guidelines of the
Electric Reliability Organization (ERO) as defined in 18 CFR 39.1, (ii)
satisfy its Control Area requirements, including all necessary
Ancillary Services, by contracting with the Transmission Provider, or
(iii) satisfy its Control Area requirements, including all necessary
Ancillary Services, by contracting with another entity, consistent with
Good Utility Practice, which satisfies the applicable reliability
guidelines of the ERO. The Transmission Provider shall not unreasonably
refuse to accept contractual arrangements with another entity for
Ancillary Services. The Network Operating Agreement is included in
Attachment G.
35.3 Network Operating Committee
A Network Operating Committee (Committee) shall be established to
coordinate operating criteria for the Parties' respective
responsibilities under the Network Operating Agreement. Each Network
Customer shall be entitled to have at least one representative on the
Committee. The Committee shall meet from time to time as need requires,
but no less than once each calendar year.
Schedule 1--Scheduling, System Control and Dispatch Service
This service is required to schedule the movement of power through,
out of, within, or into a Control Area. This service can be provided
only by the operator of the Control Area in which the transmission
facilities used for transmission service are located. Scheduling,
System Control and Dispatch Service is to be provided directly by the
Transmission Provider (if the Transmission Provider is the Control Area
operator) or indirectly by the Transmission Provider making
arrangements with the Control Area operator that performs this service
for the Transmission Provider's Transmission System. The Transmission
Customer must purchase this service from the Transmission Provider or
the Control Area operator. The charges for Scheduling, System Control
and Dispatch Service are to be based on the rates set forth below. To
the extent the Control Area operator performs this service for the
Transmission Provider, charges to the Transmission Customer are to
reflect only a pass-through of the costs charged to the Transmission
Provider by that Control Area operator.
Schedule 2--Reactive Supply and Voltage Control From Generation or
Other Sources Service
In order to maintain transmission voltages on the Transmission
Provider's transmission facilities within acceptable limits, generation
facilities and non-generation resources capable of providing this
service that are under the control of the control area operator are
operated to produce (or absorb) reactive power. Thus, Reactive Supply
and Voltage Control from Generation or Other Sources Service must be
provided for each transaction on the Transmission Provider's
transmission facilities. The amount of Reactive Supply and Voltage
Control from Generation or Other Sources Service that must be supplied
with respect to the Transmission Customer's transaction will be
determined based on the reactive power support necessary to maintain
transmission voltages within
[[Page 3138]]
limits that are generally accepted in the region and consistently
adhered to by the Transmission Provider.
Reactive Supply and Voltage Control from Generation or Other
Sources Service is to be provided directly by the Transmission Provider
(if the Transmission Provider is the Control Area operator) or
indirectly by the Transmission Provider making arrangements with the
Control Area operator that performs this service for the Transmission
Provider's Transmission System. The Transmission Customer must purchase
this service from the Transmission Provider or the Control Area
operator. The charges for such service will be based on the rates set
forth below. To the extent the Control Area operator performs this
service for the Transmission Provider, charges to the Transmission
Customer are to reflect only a pass-through of the costs charged to the
Transmission Provider by the Control Area operator.
Schedule 3--Regulation and Frequency Response Service
Regulation and Frequency Response Service is necessary to provide
for the continuous balancing of resources (generation and interchange)
with load and for maintaining scheduled Interconnection frequency at
sixty cycles per second (60 Hz). Regulation and Frequency Response
Service is accomplished by committing on-line generation whose output
is raised or lowered (predominantly through the use of automatic
generating control equipment) and by other non-generation resources
capable of providing this service as necessary to follow the moment-by-
moment changes in load. The obligation to maintain this balance between
resources and load lies with the Transmission Provider (or the Control
Area operator that performs this function for the Transmission
Provider). The Transmission Provider must offer this service when the
transmission service is used to serve load within its Control Area. The
Transmission Customer must either purchase this service from the
Transmission Provider or make alternative comparable arrangements to
satisfy its Regulation and Frequency Response Service obligation. The
amount of and charges for Regulation and Frequency Response Service are
set forth below. To the extent the Control Area operator performs this
service for the Transmission Provider, charges to the Transmission
Customer are to reflect only a pass-through of the costs charged to the
Transmission Provider by that Control Area operator.
Schedule 4--Energy Imbalance Service
Energy Imbalance Service is provided when a difference occurs
between the scheduled and the actual delivery of energy to a load
located within a Control Area over a single hour. The Transmission
Provider must offer this service when the transmission service is used
to serve load within its Control Area. The Transmission Customer must
either purchase this service from the Transmission Provider or make
alternative comparable arrangements, which may include use of non-
generation resources capable of providing this service, to satisfy its
Energy Imbalance Service obligation. To the extent the Control Area
operator performs this service for the Transmission Provider, charges
to the Transmission Customer are to reflect only a pass-through of the
costs charged to the Transmission Provider by that Control Area
operator. The Transmission Provider may charge a Transmission Customer
a penalty for either hourly energy imbalances under this Schedule or a
penalty for hourly generator imbalances under Schedule 9 for imbalances
occurring during the same hour, but not both unless the imbalances
aggravate rather than offset each other.
The Transmission Provider shall establish charges for energy
imbalance based on the deviation bands as follows: (i) Deviations
within +/-1.5 percent (with a minimum of 2 MW) of the scheduled
transaction to be applied hourly to any energy imbalance that occurs as
a result of the Transmission Customer's scheduled transaction(s) will
be netted on a monthly basis and settled financially, at the end of the
month, at 100 percent of incremental or decremental cost; (ii)
deviations greater than +/-1.5 percent up to 7.5 percent (or greater
than 2 MW up to 10 MW) of the scheduled transaction to be applied
hourly to any energy imbalance that occurs as a result of the
Transmission Customer's scheduled transaction(s) will be settled
financially, at the end of each month, at 110 percent of incremental
cost or 90 percent of decremental cost, and (iii) deviations greater
than +/-7.5 percent (or 10 MW) of the scheduled transaction to be
applied hourly to any energy imbalance that occurs as a result of the
Transmission Customer's scheduled transaction(s) will be settled
financially, at the end of each month, at 125 percent of incremental
cost or 75 percent of decremental cost.
For purposes of this Schedule, incremental cost and decremental
cost represent the Transmission Provider's actual average hourly cost
of the last 10 MW dispatched for any purpose, i.e., to supply the
Transmission Provider's Native Load Customers, correct imbalances, or
make off-system sales, based on the replacement cost of fuel, unit heat
rates, start-up costs (including any commitment and redispatch costs),
incremental operation and maintenance costs, and purchased and
interchange power costs and taxes, as applicable.
Schedule 5--Operating Reserve--Spinning Reserve Service
Spinning Reserve Service is needed to serve load immediately in the
event of a system contingency. Spinning Reserve Service may be provided
by generating units that are on-line and loaded at less than maximum
output and by non-generation resources capable of providing this
service. The Transmission Provider must offer this service when the
transmission service is used to serve load within its Control Area. The
Transmission Customer must either purchase this service from the
Transmission Provider or make alternative comparable arrangements to
satisfy its Spinning Reserve Service obligation. The amount of and
charges for Spinning Reserve Service are set forth below. To the extent
the Control Area operator performs this service for the Transmission
Provider, charges to the Transmission Customer are to reflect only a
pass-through of the costs charged to the Transmission Provider by that
Control Area operator.
Schedule 6--Operating Reserve--Supplemental Reserve Service
Supplemental Reserve Service is needed to serve load in the event
of a system contingency; however, it is not available immediately to
serve load but rather within a short period of time. Supplemental
Reserve Service may be provided by generating units that are on-line
but unloaded, by quick-start generation or by interruptible load or
other non-generation resources capable of providing this service. The
Transmission Provider must offer this service when the transmission
service is used to serve load within its Control Area. The Transmission
Customer must either purchase this service from the Transmission
Provider or make alternative comparable arrangements to satisfy its
Supplemental Reserve Service obligation. The amount of and charges for
Supplemental Reserve Service are set forth below. To the extent the
Control Area operator performs this service for the Transmission
Provider, charges to the Transmission Customer are to reflect only a
pass-through of the
[[Page 3139]]
costs charged to the Transmission Provider by that Control Area
operator.
Schedule 7--Long-Term Firm and Short-Term Firm Point-To-Point
Transmission Service
The Transmission Customer shall compensate the Transmission
Provider each month for Reserved Capacity at the sum of the applicable
charges set forth below:
(1) Yearly delivery: one-twelfth of the demand charge of $----/KW
of Reserved Capacity per year.
(2) Monthly delivery: $----/KW of Reserved Capacity per month.
(3) Weekly delivery: $----/KW of Reserved Capacity per week.
(4) Daily delivery: $----/KW of Reserved Capacity per day.
The total demand charge in any week, pursuant to a reservation for
Daily delivery, shall not exceed the rate specified in section (3)
above times the highest amount in kilowatts of Reserved Capacity in any
day during such week.
(5) Discounts: Three principal requirements apply to discounts for
transmission service as follows (1) any offer of a discount made by the
Transmission Provider must be announced to all Eligible Customers
solely by posting on the OASIS, (2) any customer-initiated requests for
discounts (including requests for use by one's wholesale merchant or an
Affiliate's use) must occur solely by posting on the OASIS, and (3)
once a discount is negotiated, details must be immediately posted on
the OASIS. For any discount agreed upon for service on a path, from
point(s) of receipt to point(s) of delivery, the Transmission Provider
must offer the same discounted transmission service rate for the same
time period to all Eligible Customers on all unconstrained transmission
paths that go to the same point(s) of delivery on the Transmission
System.
(6) Resales: The rates and rules governing charges and discounts
stated above shall not apply to resales of transmission service,
compensation for which shall be governed by section 23.1 of the Tariff.
Schedule 8--Non-Firm Point-To-Point Transmission Service
The Transmission Customer shall compensate the Transmission
Provider for Non-Firm Point-To-Point Transmission Service up to the sum
of the applicable charges set forth below:
(1) Monthly delivery: $----/KW of Reserved Capacity per month.
(2) Weekly delivery: $----/KW of Reserved Capacity per week.
(3) Daily delivery: $----/KW of Reserved Capacity per day.
The total demand charge in any week, pursuant to a reservation for
Daily delivery, shall not exceed the rate specified in section (2)
above times the highest amount in kilowatts of Reserved Capacity in any
day during such week.
(4) Hourly delivery: The basic charge shall be that agreed upon by
the Parties at the time this service is reserved and in no event shall
exceed $----/MWH. The total demand charge in any day, pursuant to a
reservation for Hourly delivery, shall not exceed the rate specified in
section (3) above times the highest amount in kilowatts of Reserved
Capacity in any hour during such day. In addition, the total demand
charge in any week, pursuant to a reservation for Hourly or Daily
delivery, shall not exceed the rate specified in section (2) above
times the highest amount in kilowatts of Reserved Capacity in any hour
during such week.
(5) Discounts: Three principal requirements apply to discounts for
transmission service as follows (1) any offer of a discount made by the
Transmission Provider must be announced to all Eligible Customers
solely by posting on the OASIS, (2) any customer-initiated requests for
discounts (including requests for use by one's wholesale merchant or an
Affiliate's use) must occur solely by posting on the OASIS, and (3)
once a discount is negotiated, details must be immediately posted on
the OASIS. For any discount agreed upon for service on a path, from
point(s) of receipt to point(s) of delivery, the Transmission Provider
must offer the same discounted transmission service rate for the same
time period to all Eligible Customers on all unconstrained transmission
paths that go to the same point(s) of delivery on the Transmission
System.
(6) Resales: The rates and rules governing charges and discounts
stated above shall not apply to resales of transmission service,
compensation for which shall be governed by section 23.1 of the Tariff.
Schedule 9--Generator Imbalance Service
Generator Imbalance Service is provided when a difference occurs
between the output of a generator located in the Transmission
Provider's Control Area and a delivery schedule from that generator to
(1) another Control Area or (2) a load within the Transmission
Provider's Control Area over a single hour. The Transmission Provider
must offer this service, to the extent it is physically feasible to do
so from its resources or from resources available to it, when
Transmission Service is used to deliver energy from a generator located
within its Control Area. The Transmission Customer must either purchase
this service from the Transmission Provider or make alternative
comparable arrangements, which may include use of non-generation
resources capable of providing this service, to satisfy its Generator
Imbalance Service obligation. To the extent the Control Area operator
performs this service for the Transmission Provider, charges to the
Transmission Customer are to reflect only a pass-through of the costs
charged to the Transmission Provider by that Control Area Operator. The
Transmission Provider may charge a Transmission Customer a penalty for
either hourly generator imbalances under this Schedule or a penalty for
hourly energy imbalances under Schedule 4 for imbalances occurring
during the same hour, but not both unless the imbalances aggravate
rather than offset each other.
The Transmission Provider shall establish charges for generator
imbalance based on the deviation bands as follows: (i) deviations
within +/-1.5 percent (with a minimum of 2 MW) of the scheduled
transaction to be applied hourly to any generator imbalance that occurs
as a result of the Transmission Customer's scheduled transaction(s)
will be netted on a monthly basis and settled financially, at the end
of each month, at 100 percent of incremental or decremental cost, (ii)
deviations greater than +/-1.5 percent up to 7.5 percent (or greater
than 2 MW up to 10 MW) of the scheduled transaction to be applied
hourly to any generator imbalance that occurs as a result of the
Transmission Customer's scheduled transaction(s) will be settled
financially, at the end of each month, at 110 percent of incremental
cost or 90 percent of decremental cost, and (iii) deviations greater
than +/-7.5 percent (or 10 MW) of the scheduled transaction to be
applied hourly to any generator imbalance that occurs as a result of
the Transmission Customer's scheduled transaction(s) will be settled at
125 percent of incremental cost or 75 percent of decremental cost,
except that an intermittent resource will be exempt from this deviation
band and will pay the deviation band charges for all deviations greater
than the larger of 1.5 percent or 2 MW. An intermittent resource, for
the limited purpose of this Schedule is an electric generator that is
not dispatchable and cannot store its fuel source and therefore cannot
respond to changes in system demand or respond to transmission security
constraints.
[[Page 3140]]
1. Notwithstanding the foregoing, deviations from scheduled
transactions in order to respond to directives by the Transmission
Provider, a balancing authority, or a reliability coordinator shall not
be subject to the deviation bands identified above and, instead, shall
be settled financially, at the end of the month, at 100 percent of
incremental and decremental cost. Such directives may include
instructions to correct frequency decay, respond to a reserve sharing
event, or change output to relieve congestion.
2. For purposes of this Schedule, incremental cost and decremental
cost represent the Transmission Provider's actual average hourly cost
of the last 10 MW dispatched for any purpose, i.e., to supply the
Transmission Provider's Native Load Customers, correct imbalances, or
make off-system sales, based on the replacement cost of fuel, unit heat
rates, start-up costs (including any commitment and redispatch costs),
incremental operation and maintenance costs, and purchased and
interchange power costs and taxes, as applicable.
Attachment A--Form of Service Agreement For Firm Point-To-Point
Transmission Service
1.0 This Service Agreement, dated as of --------, is entered into,
by and between -------- (the Transmission Provider), and --------
(``Transmission Customer'').
2.0 The Transmission Customer has been determined by the
Transmission Provider to have a Completed Application for Firm Point-
To-Point Transmission Service under the Tariff.
3.0 The Transmission Customer has provided to the Transmission
Provider an Application deposit in accordance with the provisions of
Section 17.3 of the Tariff.
4.0 Service under this agreement shall commence on the later of (1)
the requested service commencement date, or (2) the date on which
construction of any Direct Assignment Facilities and/or Network
Upgrades are completed, or (3) such other date as it is permitted to
become effective by the Commission. Service under this agreement shall
terminate on such date as mutually agreed upon by the parties.
5.0 The Transmission Provider agrees to provide and the
Transmission Customer agrees to take and pay for Firm Point-To-Point
Transmission Service in accordance with the provisions of Part II of
the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either Party regarding this
Service Agreement shall be made to the representative of the other
Party as indicated below.
Transmission Provider:
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Transmission Customer:
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7.0 The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to
be executed by their respective authorized officials.
Transmission Provider:
By:
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Name
-----------------------------------------------------------------------
Title
-----------------------------------------------------------------------
Date
Transmission Customer:
By:
-----------------------------------------------------------------------
Name
-----------------------------------------------------------------------
Title
-----------------------------------------------------------------------
Date
Specifications for Long-Term Firm Point-To-Point Transmission Service
1.0 Term of Transaction:-----------------------------------------------
Start Date:------------------------------------------------------------
Termination Date:------------------------------------------------------
2.0 Description of capacity and energy to be transmitted by
Transmission Provider including the electric Control Area in which the
transaction originates.------------------------------------------------
-----------------------------------------------------------------------
3.0 Point(s) of Receipt:-----------------------------------------------
Delivering Party:------------------------------------------------------
4.0 Point(s) of Delivery:----------------------------------------------
Receiving Party:-------------------------------------------------------
5.0 Maximum amount of capacity and energy to be transmitted (Reserved
Capacity):-------------------------------------------------------------
6.0 Designation of party(ies) subject to reciprocal service obligation:
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7.0 Name(s) of any Intervening Systems providing transmission service:-
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8.0 Service under this Agreement may be subject to some combination of
the charges detailed below. (The appropriate charges for individual
transactions will be determined in accordance with the terms and
conditions of the Tariff.)
8.1 Transmission Charge:-----------------------------------------------
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8.2 System Impact and/or Facilities Study Charge(s):-------------------
-----------------------------------------------------------------------
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8.3 Direct Assignment Facilities Charge:-------------------------------
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8.4 Ancillary Services Charges:----------------------------------------
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[FEDREG][VOL]*[/VOL][NO]*[/NO][DATE]*[/
DATE][RULES][RULE][PREAMB][AGENCY]*[/AGENCY][SUBJECT]*[/SUBJECT][/
PREAMB][SUPLINF][HED]*[/HED]Attachment A-1--Form of Service Agreement
for the Resale, Reassignment, or Transfer of Point-To-Point
Transmission Service
1.0 This Service Agreement, dated as of --------, is entered into,
by and between -------- (the Transmission Provider), and -------- (the
Assignee).
2.0 The Assignee has been determined by the Transmission Provider
to be an Eligible Customer under the Tariff pursuant to which the
transmission service rights to be transferred were originally obtained.
3.0 The terms and conditions for the transaction entered into under
this Service Agreement shall be subject to the terms and conditions of
Part II of the Transmission Provider's Tariff, except for those terms
and conditions negotiated by the Reseller of the reassigned
transmission capacity (pursuant to Section 23.1 of this Tariff) and the
Assignee, to include: contract effective and termination dates, the
amount of reassigned capacity or energy, point(s) of receipt and
delivery. Changes by the Assignee to the Reseller's Points of Receipt
and Points of Delivery will be subject to the provisions of Section
23.2 of this Tariff.
4.0 The Transmission Provider shall credit the Reseller for the
price reflected in the Assignee's Service Agreement or the associated
OASIS schedule.
5.0 Any notice or request made to or by either Party regarding this
Service Agreement shall be made to the representative of the other
Party as indicated below.
Transmission Provider:
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[[Page 3141]]
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Assignee:
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6.0 The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to
be executed by their respective authorized officials.
Transmission Provider:
By:
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Name
-----------------------------------------------------------------------
Title
-----------------------------------------------------------------------
Date
Assignee:
By:
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Name
-----------------------------------------------------------------------
Title
-----------------------------------------------------------------------
Date
Specifications for the Resale, Reassignment, or Transfer of Long-Term
Firm Point-To-Point Transmission Service
1.0 Term of Transaction:-----------------------------------------------
Start Date:------------------------------------------------------------
Termination Date:------------------------------------------------------
2.0 Description of capacity and energy to be transmitted by
Transmission Provider including the electric Control Area in which the
transaction originates.------------------------------------------------
-----------------------------------------------------------------------
3.0 Point(s) of Receipt:-----------------------------------------------
Delivering Party:------------------------------------------------------
4.0 Point(s) of Delivery:----------------------------------------------
Receiving Party:-------------------------------------------------------
5.0 Maximum amount of reassigned capacity:-----------------------------
6.0 Designation of party(ies) subject to reciprocal service obligation:
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7.0 Name(s) of any Intervening Systems providing transmission service:-
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-----------------------------------------------------------------------
8.0 Service under this Agreement may be subject to some combination
of the charges detailed below. (The appropriate charges for individual
transactions will be determined in accordance with the terms and
conditions of the Tariff.)
8.1 Transmission Charge:-----------------------------------------------
8.2 System Impact and/or Facilities Study Charge(s):-------------------
8.3 Direct Assignment Facilities Charge:-------------------------------
8.4 Ancillary Services Charges:----------------------------------------
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9.0 Name of Reseller of the reassigned transmission capacity:
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[FEDREG][VOL]*[/VOL][NO]*[/NO][DATE]*[/
DATE][RULES][RULE][PREAMB][AGENCY]*[/AGENCY][SUBJECT]*[/SUBJECT][/
PREAMB][SUPLINF][HED]*[/HED]Attachment B--Form of Service Agreement for
Non-Firm Point-To-Point Transmission Service
1.0 This Service Agreement, dated as of --------, is entered into,
by and between -------- (the Transmission Provider), and --------
(Transmission Customer).
2.0 The Transmission Customer has been determined by the
Transmission Provider to be a Transmission Customer under Part II of
the Tariff and has filed a Completed Application for Non-Firm Point-To-
Point Transmission Service in accordance with Section 18.2 of the
Tariff.
3.0 Service under this Agreement shall be provided by the
Transmission Provider upon request by an authorized representative of
the Transmission Customer.
4.0 The Transmission Customer agrees to supply information the
Transmission Provider deems reasonably necessary in accordance with
Good Utility Practice in order for it to provide the requested service.
5.0 The Transmission Provider agrees to provide and the
Transmission Customer agrees to take and pay for Non-Firm Point-To-
Point Transmission Service in accordance with the provisions of Part II
of the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either Party regarding this
Service Agreement shall be made to the representative of the other
Party as indicated below.
Transmission Provider:
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Transmission Customer:
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7.0 The Tariff is incorporated herein and made a part hereof.
IN WITNESS WHEREOF, the Parties have caused this Service Agreement to
be executed by their respective authorized officials.
Transmission Provider:
By:
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Name
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Title
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Date
Transmission Customer:
By:
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Name
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Title
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Date
Attachment C--Methodology To Assess Available Transfer Capability
The Transmission Provider must include, at a minimum, the following
information concerning its ATC calculation methodology:
(1) A detailed description of the specific mathematical algorithm
used to calculate firm and non-firm ATC (and AFC, if applicable) for
its scheduling horizon (same day and real-time), operating horizon (day
ahead and pre-schedule) and planning horizon (beyond the operating
horizon);
(2) A process flow diagram that illustrates the various steps
through which ATC/AFC is calculated; and
(3) A detailed explanation of how each of the ATC components is
calculated for both the operating and planning horizons.
(a) For TTC, a Transmission Provider shall: (i) Explain its
definition of TTC; (ii) explain its TTC calculation methodology; (iii)
list the databases used in its TTC assessments; and (iv) explain the
assumptions used in its TTC assessments regarding load levels,
generation dispatch, and modeling of planned and contingency outages.
(b) For ETC, a transmission provider shall explain: (i) Its
definition of ETC; (ii) the calculation methodology used to determine
the transmission capacity to be set aside for native load (including
network load), and non-OATT customers (including, if applicable, an
explanation of assumptions on the selection of generators that are
modeled in service); (iii) how point-to-point transmission service
requests are incorporated; (iv) how rollover rights are accounted for;
(v) its processes for ensuring that non-firm capacity is released
properly (e.g., when real-time schedules replace the associated
transmission service requests in its real-
[[Page 3142]]
time calculations); and (vi) describe the step-by-step modeling study
methodology and criteria for adding or eliminating flowgates (permanent
and temporary).
(c) If a Transmission Provider uses an AFC methodology to calculate
ATC, it shall: (i) Explain its definition of AFC; (ii) explain its AFC
calculation methodology; (iii) explain its process for converting AFC
into ATC for OASIS posting; (iv) list the databases used in its AFC
assessments; and (v) explain the assumptions used in its AFC
assessments regarding load levels, generation dispatch, and modeling of
planned and contingency outages.
(d) For TRM, a Transmission Provider shall explain: (i) Its
definition of TRM; (ii) its TRM calculation methodology (e.g., its
assumptions on load forecast errors, forecast errors in system topology
or distribution factors and loop flow sources); (iii) the databases
used in its TRM assessments; (iv) the conditions under which the
transmission provider uses TRM. A Transmission Provider that does not
set aside transfer capability for TRM must so state.
(e) For CBM, the Transmission Provider shall include a specific and
self-contained narrative explanation of its CBM practice, including:
(i) An identification of the entity who performs the resource adequacy
analysis for CBM determination; (ii) the methodology used to perform
generation reliability assessments (e.g., probabilistic or
deterministic); (iii) an explanation of whether the assessment method
reflects a specific regional practice; (iv) the assumptions used in
this assessment; and (v) the basis for the selection of paths on which
CBM is set aside.
(f) In addition, for CBM, a Transmission Provider shall: (i)
Explain its definition of CBM; (ii) list the databases used in its CBM
calculations; and (iii) demonstrate that there is no double-counting of
contingency outages when performing CBM, TTC, and TRM calculations.
(g) The Transmission Provider shall explain its procedures for
allowing the use of CBM during emergencies (with an explanation of what
constitutes an emergency, the entities that are permitted to use CBM
during emergencies and the procedures which must be followed by the
transmission providers' merchant function and other load-serving
entities when they need to access CBM). If the Transmission Provider's
practice is not to set aside transfer capability for CBM, it shall so
state.
Attachment D--Methodology for Completing a System Impact Study
To be filed by the Transmission Provider. [FEDREG][VOL]*[/
VOL][NO]*[/NO][DATE]*[/DATE][RULES][RULE][PREAMB][AGENCY]*[/
AGENCY][SUBJECT]*[/SUBJECT][/PREAMB][SUPLINF][HED]*[/HED]
Attachment E--Index of Point-To-Point Transmission Service Customers
Customer Date of Service Agreement
Attachment F--Service Agreement for Network Integration Transmission
Service
To be filed by the Transmission Provider.
Attachment G--Network Operating Agreement
To be filed by the Transmission Provider.
Attachment H--Annual Transmission Revenue Requirement for Network
Integration Transmission Service
1. The Annual Transmission Revenue Requirement for purposes of the
Network Integration Transmission Service shall be ------.
2. The amount in (1) shall be effective until amended by the
Transmission Provider or modified by the Commission.
Attachment I--Index of Network Integration Transmission Service
Customers
Customer Date of Service Agreement
Attachment J--Procedures for Addressing Parallel Flows
To be filed by the Transmission Provider.[FEDREG][VOL]*[/
VOL][NO]*[/NO][DATE]*[/DATE][RULES][RULE][PREAMB][AGENCY]*[/
AGENCY][SUBJECT]*[/SUBJECT][/PREAMB][SUPLINF][HED]*[/HED]
Attachment K--Transmission Planning Process
The Transmission Provider shall establish a coordinated, open and
transparent planning process with its Network and Firm Point-to-Point
Transmission Customers and other interested parties, including the
coordination of such planning with interconnected systems within its
region, to ensure that the Transmission System is planned to meet the
needs of both the Transmission Provider and its Network and Firm Point-
to-Point Transmission Customers on a comparable and nondiscriminatory
basis. The Transmission Provider's coordinated, open and transparent
planning process shall be provided as an attachment to the Transmission
Provider's Tariff.
The Transmission Provider's planning process shall satisfy the
following nine principles, as defined in the Final Rule in Docket No.
RM05-25-000: coordination, openness, transparency, information
exchange, comparability, dispute resolution, regional participation,
economic planning studies, and cost allocation for new projects. The
planning process shall also provide a mechanism for the recovery and
allocation of planning costs consistent with the Final Rule in Docket
No. RM05-25-000.
The Transmission Provider's planning process must include
sufficient detail to enable Transmission Customers to understand:
(i) The process for consulting with customers and neighboring
transmission providers;
(ii) The notice procedures and anticipated frequency of meetings;
(iii) The methodology, criteria, and processes used to develop
transmission plans;
(iv) The method of disclosure of criteria, assumptions and data
underlying transmission system plans;
(v) The obligations of and methods for customers to submit data to
the transmission provider;
(vi) The dispute resolution process;
(vii) The transmission provider's study procedures for economic
upgrades to address congestion or the integration of new resources; and
(viii) The relevant cost allocation procedures or principles.
Attachment L--Creditworthiness Procedures
For the purpose of determining the ability of the Transmission
Customer to meet its obligations related to service hereunder, the
Transmission Provider may require reasonable credit review procedures.
This review shall be made in accordance with standard commercial
practices and must specify quantitative and qualitative criteria to
determine the level of secured and unsecured credit.
The Transmission Provider may require the Transmission Customer to
provide and maintain in effect during the term of the Service
Agreement, an unconditional and irrevocable letter of credit as
security to meet its responsibilities and obligations under the Tariff,
or an alternative form of security proposed by the Transmission
Customer and acceptable to the Transmission Provider and consistent
with commercial practices established by the Uniform Commercial Code
that protects the Transmission Provider against the risk of non-
payment.
Additionally, the Transmission Provider must include, at a minimum,
the following information concerning its creditworthiness procedures:
(1) A summary of the procedure for determining the level of secured
and unsecured credit;
[[Page 3143]]
(2) A list of the acceptable types of collateral/security;
(3) A procedure for providing customers with reasonable notice of
changes in credit levels and collateral requirements;
(4) A procedure for providing customers, upon request, a written
explanation for any change in credit levels or collateral requirements;
(5) A reasonable opportunity to contest determinations of credit
levels or collateral requirements; and
(6) A reasonable opportunity to post additional collateral,
including curing any non-creditworthy determination.
[FR Doc. E8-144 Filed 1-15-08; 8:45 am]
BILLING CODE 6717-01-P