[Federal Register Volume 73, Number 11 (Wednesday, January 16, 2008)]
[Rules and Regulations]
[Pages 2984-3143]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-144]



[[Page 2983]]

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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

  Federal Register / Vol. 73, No. 11 / Wednesday, January 16, 2008 / 
Rules and Regulations  

[[Page 2984]]


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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.

[[Page 2985]]

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

    32. NRECA requests clarification, or in the alternative rehearing, 
that the Commission did not intend in Order No. 890 to extend 
reciprocity obligations beyond transmission owning members of an ISO or 
RTO. NRECA contends that the Commission's modification to the pro forma 
OATT creates ambiguity by imposing the reciprocity obligation for all 
``members'' of an ISO or RTO. NRECA points out that some members of 
ISOs and RTOs do not own transmission, such as transmission dependent 
utilities, state regulatory authorities and eligible end-use customers. 
NRECA argues that expanding the reciprocity obligation to require non-
public utility transmission providers to provide service to non-
transmission owning members of an ISO or RTO would contradict 
Commission precedent \23\ and be unsupported by the record in this 
proceeding.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

[[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\
---------------------------------------------------------------------------

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

    \42\ Citing Order No. 888-A at P 30,220.
---------------------------------------------------------------------------

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

[[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\
---------------------------------------------------------------------------

    \55\ See Order No. 890 at P 369.
---------------------------------------------------------------------------

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

    \56\ 18 CFR 388.113.
---------------------------------------------------------------------------

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

    \57\ See Order No. 890 at P 404.
---------------------------------------------------------------------------

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

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

    \60\ See Order No. 890 at P 416.
    \61\ See id. at P 417.
---------------------------------------------------------------------------

(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.
---------------------------------------------------------------------------

    \62\ See id. at P 348.
---------------------------------------------------------------------------

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

    \63\ See id. at P 323.
---------------------------------------------------------------------------

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

    \64\ See id. at P 348.
    \65\ See Order No. 888 at 31,655.
---------------------------------------------------------------------------

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

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

    \67\ Citing New York v. FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------

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

    \68\ Citing pro forma OATT sections 13.5, 15.4 and 28.2.
---------------------------------------------------------------------------

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

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

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

    \70\ See Order No. 890 at P 437.
---------------------------------------------------------------------------

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

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

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

    \72\ See id. at P 440.
---------------------------------------------------------------------------

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

    \73\ See id. at P 594.
---------------------------------------------------------------------------

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

    \74\ See Order No. 890 at P 453.
---------------------------------------------------------------------------

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

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

    \76\ See Order No. 888-A at 30,286.
    \77\ See Order No. 890 at P 474.
---------------------------------------------------------------------------

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

    \78\ See id. at P 472.
---------------------------------------------------------------------------

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

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

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

    \80\ See id. at P 494.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(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\
---------------------------------------------------------------------------

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

    \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.
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    \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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[[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.
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    \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.
---------------------------------------------------------------------------

    \162\ The EQR for reassignments of transmission capacity must 
contain all relevant transaction data, whether stated in the service 
agreement or related OASIS schedule.
---------------------------------------------------------------------------

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

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

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

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

    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.
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    \168\ See Order No. 890 at P 815.
---------------------------------------------------------------------------

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

    \187\ Citing Order No. 890 at P 865; Cleco Corp., 104 FERC ] 
61,125 at 61,441 (2003).
---------------------------------------------------------------------------

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

    \189\ See Policy Statement on Enforcement at P 20 (indicating 
that assessment of penalties should take account of the financial 
viability of the offender).
---------------------------------------------------------------------------

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

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

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

    \191\ See pro forma OATT section 13.2.
---------------------------------------------------------------------------

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

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

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

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

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

    \195\ See Order No. 890 at P 898.
---------------------------------------------------------------------------

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

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

    \198\ E.g., Ameren, NRECA, and TDU Systems.
    \199\ E.g., E.ON LSE, NRECA, and TDU Systems.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

    \219\ See Order No. 890 at P 135, n.106.
---------------------------------------------------------------------------

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

    \220\ See id. at P 1093.
---------------------------------------------------------------------------

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

    \221\ See id. at P 1612.
    \222\ See id. at P 1047.
---------------------------------------------------------------------------

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

    \223\ See, e.g., id. at P 4, 78, and 911.
---------------------------------------------------------------------------

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

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

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

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

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

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

    \228\ E.g., Ameren, NRECA, and Southern.
---------------------------------------------------------------------------

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

    \229\ Citing Order No. 890 at P 1601.
---------------------------------------------------------------------------

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

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

    \231\ See id. at P 980.
---------------------------------------------------------------------------

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

    \232\ See id. at P 1004-07.
---------------------------------------------------------------------------

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

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

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

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

    \239\ E.g., Ameren, EEI, Progress, Southern, Washington IOUs, 
and Xcel.
---------------------------------------------------------------------------

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

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

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

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

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

    \243\ See Order No. 888 at 31,739.
    \244\ See Order No. 888-A at 30,265, n.261.
    \245\ Id.
---------------------------------------------------------------------------

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

    \246\ See Order No. 888 at 31,740.
---------------------------------------------------------------------------

(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.
---------------------------------------------------------------------------

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

    \248\ See Order No. 890 at P 1091.
---------------------------------------------------------------------------

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

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

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

    \250\ Citing Order No. 890 at P 1162, n.707.
---------------------------------------------------------------------------

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

    \251\ See id. at P 1150.
---------------------------------------------------------------------------

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

    \252\ See id. at P 1163.
    \253\ See id. at P 1159.
---------------------------------------------------------------------------

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

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

    \255\ See Wisconsin Pub. Power Inc. SYSTEM v. Wisconsin Pub. 
Serv. Corp., 84 FERC ] 61,120 at 61,659 (1998) (WPPI).
---------------------------------------------------------------------------

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

    \257\ See Order No. 888-A at 30,198, n.52 (citing Order No. 888 
at 31,665, n.176).
---------------------------------------------------------------------------

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

    \258\ See Order No. 890 at P 1236.
---------------------------------------------------------------------------

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

    \260\ See id. at P 1246.
---------------------------------------------------------------------------

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

    \261\ See Order No. 888-A at 30,197.
---------------------------------------------------------------------------

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

    \262\ See Order No. 890 at P 1255 (citing Order No. 888-A at 
30,197).
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

    \283\ Order No. 890 at P 1285.
---------------------------------------------------------------------------

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

    \284\ Old Dominion also argues that the Commission should 
require performance reports regarding transmission planning 
activities, which the Commission addresses in section III.B.
---------------------------------------------------------------------------

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

    \285\ See Order No. 890 at P 1308.
---------------------------------------------------------------------------

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

    \286\ See id. at P 1309.
    \287\ 18 CFR 37.6(h)(1).
---------------------------------------------------------------------------

(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.
---------------------------------------------------------------------------

    \288\ See Order No. 890 at P 1340.
---------------------------------------------------------------------------

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

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

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

    \291\ Id. at P 1357.
---------------------------------------------------------------------------

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

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

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

    \293\ Citing Order No. 890 at P 1390.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

    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

[[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\
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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\
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    \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.
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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 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
[email protected].

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

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    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

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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

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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

[[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:
-----------------------------------------------------------------------

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:

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

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

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


7.0 Name(s) of any Intervening Systems providing transmission service:-

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

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):-------------------

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

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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:
-----------------------------------------------------------------------

Name
-----------------------------------------------------------------------

Title
-----------------------------------------------------------------------

Date

    Assignee:
    By:
-----------------------------------------------------------------------

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:

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

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

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

7.0 Name(s) of any Intervening Systems providing transmission service:-

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

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

    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:
-----------------------------------------------------------------------

Name

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

Title

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

Date

    Transmission Customer:

    By:
-----------------------------------------------------------------------

Name

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

Title

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

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