Document ID: FERC-2006-1104-0001
Agency: ferc
Document Type: Proposed Rule
Title: Preventing Undue Discrimination and Preference in Transmission Service
Posted Date: 2006-06-06T04:00Z

[Federal Register: June 6, 2006 (Volume 71, Number 108)]
[Proposed Rules]               
[Page 32635-32744]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr06jn06-19]                         
 

[[Page 32635]]

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Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Parts 35 and 37

Preventing Undue Discrimination and Preference in Transmission Service; 
Proposed Rule

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 35 and 37

[Docket Nos. RM05-25-000 and RM05-17-000]

 
Preventing Undue Discrimination and Preference in Transmission 
Service

May 19, 2006.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission is proposing 
amendments to its regulations adopted in Order Nos. 888 and 889, and to 
the pro forma open access transmission tariff, to ensure that 
transmission services are provided on a basis that is just, reasonable 
and not unduly discriminatory or preferential.

DATES: Comments are due August 7, 2006. Reply comments are due 
September 5, 2006.

ADDRESSES: You may submit comments, identified by Docket Nos. RM05-25-
000 and RM05-17-000, by one of the following methods:
     Agency Web site: http://www.ferc.gov. Follow the 

instructions for submitting comments via the eFiling link found in the 
Comment Procedures section of the preamble.
     Mail: Commenters unable to file comments electronically 
must mail or hand deliver an original and 14 copies of their comments 
to: Federal Energy Regulatory Commission, Office of the Secretary, 888 
First Street, NE., Washington, DC 20426. Please refer to the Comment 
Procedures section of the preamble for additional information on how to 
file paper comments.

FOR FURTHER INFORMATION CONTACT: Daniel Hedberg (Technical 
Information), Office of Energy Markets and Reliability, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, DC 20426, 
(202) 502-6243.
    Kathleen Barron (Legal Information), Office of the General 
Counsel--Energy Markets, Federal Energy Regulatory Commission, 888 
First Street, NE., Washington, DC 20426, (202) 502-6461.
    David Withnell (Legal Information), Office of the General Counsel--
Energy Markets, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426. (202) 502-8421.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction
II. Background
    A. Historical Antecedent
    B. Order No. 888 and Subsequent Reforms
    C. EPAct 2005 and Recent Developments
III. The Need for Reform of Order No. 888
    A. Opportunities for Undue Discrimination Continue To Exist
    B. A Lack Of Transparency Undermines Confidence in Open Access 
and Impedes Enforcement of Open Access Requirements
    C. Congestion and Inadequate Infrastructure Development Impede 
Customers' Use of the Grid
    D. A Consistent Method of Measuring ATC Has Not Been Established
    E. A Number of Transmission Pricing Policies May Impede the Use 
of the Grid
    F. EPAct 2005 Emphasized Certain Policies and Priorities for the 
Commission
IV. Summary, Scope and Applicability of the Proposed Rule
    A. Summary of Proposed Reforms .
    B. Core Elements of Order No. 888 That Are Retained
    1. Federal/State Jurisdiction
    2. Native Load Protection
    3. The Types of Transmission Services Offered
    4. Functional Unbundling
    C. Applicability of the Proposed Rule
    1. Public Utility Transmission Providers
    2. Non-Public Utility Transmission Providers/Reciprocity
V. Proposed Modifications of the OATT
    A. Consistency and Transparency of ATC Calculations
    B. Transmission Planning--Coordinated, Open and Transparent 
Planning
    C. Transmission Pricing
    1. Imbalances
    2. Credits for Network Customers
    3. Capacity Reassignment
    4. ``Operational'' Penalties
    a. Unauthorized Use Penalties
    b. How Transmission Providers Should Pay Operational Penalties
    5. ``Higher of'' Pricing Policy
    D. Non-Rate Terms and Conditions
    1. Potential Modifications to Long-Term Firm Point-to-Point 
Service
    2. Hourly Firm Service
    3. Rollover Rights
    4. Modification of Receipt or Delivery Points
    5. Acquisition of Transmission Service
    a. Processing of Service Requests
    b. Queue Processing Business Practices
    c. Reservation Priority
    6. Designation of Network Resources
    a. Qualification as a Network Resource
    b. Documentation for Network Resources
    c. Undesignation of Network Resources
    7. Clarifications Related to Network Service
    8. Transmission Curtailments
    9. Standardization of Rules and Practices
    10. OATT Definitions
    E. Enforcement
    1. General Policy
    a. Compliance Review Regime
    b. Use of Independent Third Party Audits
    2. Civil Penalties
    a. Background
    b. Whether Civil Penalties Should Be Specified in the OATT
    c. Whether Transmission Providers Should Be Subject to 
Revocation of Their Market-Based Rates for OATT Violations.
    d. Whether Certain OATT Violations Should Be Considered Market 
Manipulation Under the Market Behavior Rules and Section 1283 of 
EPAct 2005
VI. Information Collection Statement
VII. Environmental Analysis
VIII. Regulatory Flexibility Act Analysis
IX. Comment Procedures
X. Document Availability
Appendix A: Commenter Acronyms
Appendix B: Pro Forma Open Access Transmission Tariff

I. Introduction

    1. Ten years have passed since the Commission issued its landmark 
Order No. 888.\1\ Named after our new headquarters in Washington, DC, 
Order No. 888 sought to eradicate undue discrimination in the provision 
of transmission service in interstate commerce. It did so by requiring 
that each public utility that owns, operates, or controls facilities 
used for transmission in interstate commerce offer unbundled 
transmission service pursuant to a standard Open Access Transmission 
Tariff (pro forma OATT) and separate its transmission and merchant 
generation functions pursuant to a companion order issued that same 
day, Order No. 889.\2\ These remedies reduced barriers to entry, led to 
greater competition in bulk power markets and provided the foundation 
for subsequent regulatory reforms at both the federal and state level.
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    \1\ Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities; Recovery 
of Stranded Costs by Public Utilities and Transmitting Utilities, 
Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. ] 
31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar. 
14, 1997), FERC Stats. & Regs. ] 31,048 (1997), order on reh'g, 
Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 
888-C, 82 FERC ] 61,046 (1998), aff'd in relevant part sub nom. 
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. 
Cir. 2000) (TAPS v. FERC), aff'd sub nom. New York v. FERC, 535 U.S. 
1 (2002).
    \2\ Open Access Same-Time Information System (Formerly Real-Time 
Information Networks) and Standards of Conduct, Order No. 889, 61 FR 
21737 (May 10, 1996), FERC Stats. & Regs. ] 31,035 (1996), order on 
reh'g, Order No. 889-A, FERC Stats. & Regs. ] 31,049 (1997), order 
on reh'g, Order No. 889-B, 81 FERC ] 61,253 (1997).
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    2. Although Order No. 888 has been successful in many important 
respects, the need for reform of the Order No. 888 pro forma OATT has 
been apparent for some time. In 1999, the Commission held, in adopting 
Order No. 2000,\3\ that

[[Page 32637]]

the pro forma OATT could not fully remedy undue discrimination because 
transmission providers retained both the incentive and the ability to 
discriminate against third parties, particularly in areas where the pro 
forma OATT left the transmission provider with significant 
discretion.\4\ The Commission in Order No. 2000 thus encouraged 
utilities to voluntarily join independent regional transmission 
organizations (RTOs) that would operate their transmission facilities 
on a non-discriminatory basis and administer the OATT. The Commission 
based Order No. 2003 on a similar finding, explaining that the 
interconnection process includes opportunities for undue discrimination 
that may lead to delays that benefit generation-owning transmission 
utilities and undermine competition.\5\ While many regions of the 
country now have independent grid operators, not all do, and changes to 
the pro forma OATT are necessary to reduce the opportunity for 
transmission providers to engage in undue discrimination. In the past 
ten years new investment has faltered and many regions now experience 
chronic transmission congestion and inadequate infrastructure. 
Congress, through the Energy Policy Act of 2005 (EPAct 2005),\6\ 
recognized this problem and provided the Commission not only new tools 
to encourage infrastructure but also made clear that the Commission 
should use its existing authority to ensure an adequate infrastructure 
to support a vibrant economy.
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    \3\ Regional Transmission Organizations, Order No. 2000, 65 FR 
809 (Jan. 6, 2000), FERC Stats. & Regs. ] 31,089 (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).
    \4\ Order No. 2000 at 31,015.
    \5\ See Order No. 2003 at P 11-12.
    \6\ Pub. L. 109-58, 119 Stat. 594 (to be codified in scattered 
itles of the U.S.C.).
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    3. The reforms we propose today are intended to address 
deficiencies in the pro forma OATT that have become apparent since 1996 
and to facilitate improved planning and operation of transmission 
facilities. We summarize these reforms in Part IV.A below, but note the 
major focus of this reform effort here. As a general matter, the 
purpose of this rulemaking is to strengthen the pro forma OATT to 
ensure that it achieves its original purpose--remedying undue 
discrimination--not to create new market structures. We propose to 
achieve this goal by increasing the clarity and transparency of the 
rules applicable to the planning and use of the transmission system and 
by addressing ambiguities and the lack of sufficient detail in several 
important areas of the pro forma OATT. The lack of specificity in the 
pro forma OATT creates opportunities for undue discrimination as well 
as making the undue discrimination that does occur more difficult to 
detect. First, we propose to improve transparency and consistency in 
several critical areas, such as the calculation of available transfer 
capability (ATC).\7\ We propose to direct public utilities, under the 
auspices of the North American Electric Reliability Council (NERC) and 
the North American Energy Standards Board (NAESB), to provide for 
greater consistency in ATC calculation. By reducing unnecessarily broad 
discretion in this and other areas, we will reduce the ability of 
transmission providers to unduly discriminate and provide them greater 
certainty to facilitate compliance with our regulations. Second, we 
propose to reform the transmission planning requirements of the pro 
forma OATT to eliminate potential undue discrimination and support the 
construction of adequate transmission facilities to meet the needs of 
all load-serving entities. The pro forma OATT contains only minimal 
requirements regarding transmission planning, which have proven to be 
inadequate as the Nation faces inadequate transmission investment in 
many areas. We propose to require public utilities to engage in an open 
and transparent planning process at both the local and regional levels. 
Third, we propose to remedy certain portions of the pro forma OATT that 
may have permitted utilities to discriminate against new merchant 
generation, including intermittent generation. For example, we propose 
to modify the energy imbalance provisions of the pro forma OATT and 
adopt certain other tariff modifications. Fourth, we provide for 
greater transparency in the provision of transmission service to allow 
transmission customers better access to information to make their 
resource procurement and investment decisions, as well as to increase 
our ability to detect any remaining incidents of undue discrimination. 
Finally, we provide for reform and greater clarity in areas that have 
generated recurring disputes over the past 10 years, such as rollover 
rights, ``redirects,'' and generation redispatch.
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    \7\ We note that the Commission used the term ``Available 
Transmission Capability'' in Order No. 888 to describe the amount of 
additional capability available in the transmission network to 
accommodate additional requests for transmission services. To be 
consistent with the term generally accepted throughout the industry, 
the Commission is proposing to revise the pro forma OATT to adopt 
the term ``Available Transfer Capability.''
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    4. Although the reforms being proposed in these areas are 
significant, we wish to underscore that we propose to maintain many of 
the core elements of Order No. 888. For example, we are retaining the 
comparability requirement under which each public utility must treat 
third parties in a manner comparable to its service to bundled 
customers. We are retaining the basic nature of the services being 
offered--network service and point-to-point service. We are retaining 
the protection of native load customers embodied in Order No. 888, 
consistent with EPAct 2005's new requirement that load-serving entities 
be provided transmission rights to meet their service obligations.\8\ 
We are retaining our decision to exercise jurisdiction over unbundled 
transmission service, but not transmission service provided as part of 
a bundled retail service. We are retaining the use of functional 
unbundling to address undue discrimination, rather than requiring 
corporate unbundling. We are retaining the use of an OATT to facilitate 
the development of competitive wholesale markets by reducing barriers 
to entry through the control of transmission assets, not imposing any 
particular market structure on the industry.
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    \8\ EPAct 2005 sec. 1233 (to be codified at section 217(b)(4) of 
the FPA, 16 U.S.C. 824q).
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    5. In proposing to reform Order No. 888, we have relied heavily on 
the comments received in response to our notices of inquiry in the 
above-captioned dockets.\9\ We appreciate the time and thoughtfulness 
of all sectors of the industry in preparing comments on these notices 
of inquiry. We have found them very informative and useful and this 
Notice of Proposed Rulemaking (NOPR) incorporates many of the 
commenters' suggestions. We invite further comments on this NOPR. We 
also are scheduling technical conferences to more fully address the 
topics of ATC calculation and transmission planning.
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    \9\ Preventing Undue Discrimination and Preference in 
Transmission Services, Notice of Inquiry, 112 FERC ] 61,299 (2005) 
(NOI); Information Requirements for Available Transfer Capability, 
Notice of Inquiry, 111 FERC ] 61,274 (2005) (ATC NOI).
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II. Background

A. Historical Antecedent

    6. In the first few decades after enactment of the Federal Power 
Act (FPA) in 1935, the industry was characterized mostly by self-
sufficient, vertically integrated electric utilities, in which 
generation, transmission, and distribution facilities were owned by a 
single entity and sold as part of a bundled service to wholesale and 
retail customers. Most electric utilities built their own power plants 
and transmission systems, entered into interconnection and coordination 
arrangements with neighboring utilities,

[[Page 32638]]

and entered into long-term contracts to make wholesale requirements 
sales (bundled sales of generation and transmission) to municipal, 
cooperative, and other investor-owned utilities connected to each 
utility's transmission system. Each system covered a limited service 
area, which was defined by the retail franchise decisions of state 
regulatory agencies. This structure of separate systems arose naturally 
due primarily to the cost and technological limitations on the distance 
over which electricity could be transmitted.
    7. A number of statutory, economic, and technological developments 
in the 1970s led to an increase in coordinated operations and 
competition. Among those was the passage of the Public Utility 
Regulatory Policies Act of 1978 (PURPA),\10\ which was designed to 
lessen dependence on foreign fossil fuels by encouraging the 
development of alternative generation sources and imposing a mandatory 
purchase obligation on utilities for generation from such sources. 
PURPA also enabled the Commission to order wheeling of electricity 
under limited circumstances.\11\ The rapid expansion and performance of 
the independent power industry following the enactment of PURPA 
demonstrated that traditional, vertically integrated public utilities 
need not be the only sources of reliable power. During this period, the 
profile of generation investment began to change, and a market for non-
traditional power supply beyond the purchases required by PURPA began 
to emerge. The economic and technological changes in the transmission 
and generation sectors helped encourage many new entrants in the 
generating markets that could sell electric energy profitably with 
smaller scale technology at a lower price than many utilities selling 
from their existing generation facilities at rates reflecting cost. 
However, it became increasingly clear that the potential consumer 
benefits that could be derived from these technological advances could 
be realized only if more efficient generating plants could obtain 
access to the regional transmission grids. Because many traditional 
vertically integrated utilities still did not provide open access to 
third parties and favored their own generation if and when they 
provided transmission access to third parties, access to cheaper, more 
efficient generation sources remained limited.
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    \10\ Pub. L. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C. 
titles 15, 16, 26, 30, 42, and 43 (2000)).
    \11\ Section 211 of the FPA, 16 U.S.C. 824j (2000). In earlier 
years, a few customers were able to obtain access as a result of 
litigation, beginning with the U.S. Supreme Court's decision in 
Otter Tail Power Company v. United States, 410 U.S. 366 (1973). 
Additionally, some customers gained access by virtue of Nuclear 
Regulatory Commission license conditions and voluntary preference 
power transmission arrangements associated with federal power 
marketing agencies. See, e.g., Consumers Power Co., 6 NRC 887, 1036-
44 (1977); Toledo Edison Co., 10 NRC 265, 327-34 (1979); Florida 
Municipal Power Agency v. Florida Power and Light Company, 839 F. 
Supp. 1563 (M.D. Fla. 1993).
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    8. The Commission encouraged the development of independent power 
producers (IPPs), as well as emerging power marketers, by authorizing 
market-based rates for their power sales on a case-by-case basis and by 
encouraging more widely available transmission access on a case-by-case 
basis. Market-based rates helped to develop competitive bulk power 
markets by allowing generating utilities to move more quickly and 
flexibly to take advantage of short-term or even long-term market 
opportunities than those utilities operating under traditional cost-of-
service tariffs. In approving these market-based rates, the Commission 
required that the seller and its affiliates lack market power or 
mitigate any market power that they may have possessed.\12\ The major 
concern of the Commission was whether the seller or its affiliates 
could limit competition and thereby drive up prices. A key inquiry 
became whether the seller or its affiliates owned or controlled 
transmission facilities in the relevant service area and therefore, by 
denying access or imposing discriminatory terms or conditions on 
transmission service, could foreclose other generators from competing. 
Beginning in the late 1980s, in order to mitigate their market power to 
meet the Commission's conditions, public utilities seeking Commission 
authorization for blanket approval of market-based rates for generation 
services under section 205 of the FPA filed ``open access'' 
transmission tariffs of general applicability.\13\ The Commission also 
approved proposed mergers under section 203 of the FPA on the condition 
that the merging companies remedy anticompetitive effects potentially 
caused by the merger by filing ``open access'' tariffs. The early 
tariffs submitted in market-based rate proceedings under section 205 
and merger proceedings under section 203 did not, however, provide 
access to the transmission system that was comparable to the service 
the transmission providers used for their own purposes. Rather, they 
typically made available only point-to-point transmission service, 
i.e., service from a single point of receipt to a single point of 
delivery. As these early tariffs were offered only by transmission 
providers that volunteered to provide service to third parties, they 
resulted in a patchwork of open access that was not sufficient to 
facilitate wholesale generation markets.
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    \12\ See, e.g., Dartmouth Power Associates Limited Partnership, 
53 FERC ] 61,117 (1990); Commonwealth Atlantic Limited Partnership, 
51 FERC ] 61,368 (1990); Doswell Limited Partnership, 50 FERC ] 
61,251 (1990); Citizens Power & Light Co., 48 FERC ] 61,210 (1989); 
Ocean State Power, 44 FERC ] 61,261 (1988); and Orange and Rockland 
Utilities, Inc., 42 FERC ] 61,012 (1988).
    \13\ See Order No. 888 at 31,644 n.52.
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    9. In response to the competitive developments following PURPA, and 
the fact that limited transmission access and significant regulatory 
barriers continued to constrain the development of generation by 
independent power producers, Congress enacted Title VII of the Energy 
Policy Act of 1992 (EPAct 1992).\14\ EPAct 1992 reduced regulatory 
barriers to entry by creating a class of ``Exempt Wholesale 
Generators'' that were exempt from the requirements of the Public 
Utility Holding Company Act of 1935.\15\ EPAct 1992 also expanded the 
Commission's authority to approve applications for transmission 
services under sections 211 and 212 of the FPA. Though the Commission 
aggressively implemented expanded section 211, it ultimately concluded 
that the procedural limitations in section 211 thwarted the 
Commission's ability to effectively eliminate undue discrimination in 
the provision of transmission service.
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    \14\ Pub. L. 102-486, 106 Stat. 2776 (1992) (codified at, among 
other places, 15 U.S.C. 79z-5a and 16 U.S.C. 796 (22-25), 824j-l 
(2000)).
    \15\ 15 U.S.C. 79a (2000), repealed by EPAct 2005 sec. 1263; see 
Repeal of the Public Utility Holding Company Act of 1935 and 
Enactment of the Public Utility Holding Company Act of 2005, Order 
No. 667, 70 FR 75592 (Dec. 20, 2005), FERC Stats. & Regs. ] 31,197 
(2005).
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B. Order No. 888 and Subsequent Reforms

    10. In April 1996, as part of its statutory obligation under 
sections 205 and 206 of the FPA to remedy undue discrimination, the 
Commission adopted Order No. 888 prohibiting public utilities from 
using their monopoly power over transmission to unduly discriminate 
against others. In that order, the Commission required all public 
utilities that own, control or operate facilities used for transmitting 
electric energy in interstate commerce to file open access non-
discriminatory transmission tariffs that contained minimum terms and 
conditions of non-discriminatory service. It also obligated such public 
utilities to ``functionally unbundle'' their generation and 
transmission services. This meant public utilities had to take 
transmission service (including ancillary services) for

[[Page 32639]]

their own new wholesale sales and purchases of electric energy under 
the open access tariffs, and to separately state their rates for 
wholesale generation, transmission and ancillary services.\16\ Each 
public utility was required to file the pro forma OATT included in 
Order No. 888 without any deviation (except a limited number of terms 
and conditions that reflect regional practices).\17\ After the 
effectiveness of their OATTs, public utilities were allowed to file, 
pursuant to section 205 of the FPA, deviations that were consistent 
with or superior to the pro forma OATT's terms and conditions. Because 
certain owners and controllers or operators of interstate transmission 
facilities were not subject to the Commission's jurisdiction under 
sections 205 and 206 and thus were not subject to Order No. 888, the 
Commission adopted a reciprocity provision in the pro forma OATT which 
conditions the use by non-public utilities of public utilities' open 
access services on an agreement to offer open access services in 
return.
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    \16\ This is known as ``functional unbundling'' because the 
transmission element of a wholesale sale is separated or unbundled 
from the generation element of that sale, although the public 
utility may retain ownership over both functions. See infra Part 
IV.B.4.
    \17\ See Order No. 888 at 31,769-70 (noting that the pro forma 
OATT expressly identified certain non-rate terms and conditions, 
such as the time deadlines for determining available capability in 
section 18.4 or scheduling changes in sections 13.8 and 14.6, that 
may be modified to account for regional practices if such practices 
are reasonable, generally accepted in the region, and consistently 
adhered to by the transmission provider).
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    11. In addition to imposing the functional unbundling requirement, 
the Commission also encouraged broader reforms through the formation of 
independent system operators (ISOs). The Commission stated that ISOs 
``have the potential to provide significant benefits (e.g., to help 
provide regional efficiencies, to facilitate economically efficient 
pricing, and, especially in the context of power pools, to remedy undue 
discrimination and mitigate market power) and will further our goal of 
achieving a workably competitive market.'' \18\ While the Commission 
declined to mandate ISOs, it set forth eleven principles for assessing 
ISO proposals submitted to the Commission.\19\
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    \18\ Order No. 888 at 31,655.
    \19\ Id. at 31,730-32.
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    12. Order No. 888 also clarified the Commission's interpretation of 
the federal/state jurisdictional boundaries over transmission and local 
distribution. While it reaffirmed that the Commission has exclusive 
jurisdiction over the rates, terms, and conditions of unbundled retail 
transmission in interstate commerce by public utilities, it 
nevertheless recognized the legitimate concerns of state regulatory 
authorities regarding the transmission component of bundled retail 
sales. The Commission therefore declined to extend its unbundling 
requirement to the transmission component of bundled retail sales. On 
appeal, the U.S. Supreme Court affirmed this element of Order No. 888, 
finding that the Commission made a statutorily permissible choice.\20\
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    \20\ New York v. FERC, 535 U.S. 1 (2002).
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    13. The same day it issued Order No. 888, the Commission issued a 
companion order, Order No. 889, addressing both the separation of 
vertically integrated utilities' transmission and merchant functions, 
the information transmission providers were required to make public and 
the electronic means they were required to use to do so. Order No. 889 
imposed Standards of Conduct governing the separation of, and 
communications between, the utility's transmission and wholesale power 
functions, to prevent the utility from giving its merchant arm 
preferential access to transmission information. All public utilities 
that owned, controlled or operated facilities used in the transmission 
of electric energy in interstate commerce were required to create or 
participate in an Open Access Same-Time Information System (OASIS) that 
was to provide existing and potential transmission customers the same 
access to transmission information.
    14. Among the information required to be posted by Order No. 889 
was the transmission provider's calculation of ATC. Though the 
Commission acknowledged that before-the-fact measurement of the 
availability of transmission service is ``difficult,'' it concluded 
that it was important to give potential transmission customers ``an 
easy-to-understand indicator of service availability.'' \21\ Because 
formal methods did not then exist to calculate ATC and total transfer 
capability (TTC), the Commission encouraged industry efforts to develop 
consistent methods for calculating ATC and TTC.\22\ Order No. 889 
ultimately required transmission providers to base their calculations 
on ``current industry practices, standards and criteria'' and to 
describe their methodology in their tariffs.\23\ The Commission noted 
that the requirement that transmission providers purchase only ATC that 
is posted as available ``should create an adequate incentive for them 
to calculate ATC and TTC as accurately and as uniformly as possible.'' 
\24\
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    \21\ Order No. 889 at 31,605.
    \22\ Id. at 31,607.
    \23\ Id.
    \24\ Id.
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    15. The electric industry continued to undergo economic and 
regulatory changes in the years following the issuance of Order No. 
888. Retail access was adopted by approximately 25 states in the late 
1990s.\25\ This state restructuring activity spurred significant 
changes at the wholesale level as well by encouraging or requiring the 
divestiture of generation plants by traditional electric utilities and 
the development of ISOs that could manage short-term energy markets 
necessary to support retail access. At the same time, there was a 
significant increase in the number of mergers between traditional 
electric utilities and between electric utilities and gas pipeline 
companies, and large increases in the number of power marketers and 
independent generation facility developers entering the marketplace. 
Trade in bulk power markets increased significantly and the Nation's 
transmission grid was used more heavily and in new ways as customers 
took advantage of the pro forma OATT and purchased power from 
competitive sellers.
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    \25\ See Energy Information Administration, Retail Unbundling--
U.S. Summary (2005), http://www.eia.doe.gov/oil_gas/natural_gas/restructure/state/us.html
.

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    16. In the wake of these changes, in December 1999, the Commission 
adopted Order No. 2000.\26\ That rulemaking recognized that Order No. 
888 set the foundation upon which competitive electric markets could 
develop, but did not eliminate the potential to engage in undue 
discrimination and preference in the provision of transmission 
service.\27\ The rulemaking also recognized that Order No. 888 did not 
address the regional nature of the grid, including the treatment of 
parallel flows, pancaked rates, and congestion management. Thus, the 
Commission encouraged the creation of RTOs to address important 
operational and reliability issues and eliminate any residual 
discrimination in transmission services that can occur when the 
operation of the transmission system remains in the control of a 
vertically integrated utility. The Commission found that RTOs would 
increase the efficiency of wholesale markets by eliminating pancaked 
rates, internalizing parallel flow, managing congestion efficiently and 
operating markets for energy, capacity and ancillary services. The 
Commission

[[Page 32640]]

established an open, collaborative process that relied on voluntary 
regional participation to design RTOs tailored to the specific needs of 
each region. The Commission noted, however, that ``[i]f the industry 
fails to form RTOs under this approach, the Commission will reconsider 
what further regulatory steps are in the public interest.'' \28\
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    \26\ See supra note 3.
    \27\ Order No. 2000 at 31,015.
    \28\ Id. at 30, 993.
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    17. Following Order No. 2000, RTOs were approved in several regions 
of the country including the Northeast (PJM Interconnection, Inc.; ISO 
New England), the Midwest (MISO) and the South (SPP). In most cases, 
RTOs have assumed responsibility for calculating ATC across the 
footprint of the RTO, as well as the planning and expansion of the 
transmission grid, at least for facilities necessary for maintaining 
system reliability. However, large areas of the Nation have not 
developed RTOs using the voluntary structure adopted by the Commission 
in Order No. 2000. Moreover, transmission customers have complained 
that even in RTO markets there are instances when comparable 
transmission service is not provided, particularly in the area of 
transmission planning.

C. EPAct 2005 and Recent Developments

    18. EPAct 2005,\29\ enacted on August 8, 2005, added a number of 
new authorities and priorities for the Commission and emphasized 
certain of its existing obligations. Specifically, EPAct 2005 
recognized the importance of adequate transmission infrastructure 
development and its role in facilitating the development of competitive 
wholesale markets. For example, Congress required the Commission to 
adopt a rule establishing incentive ratemaking for transmission 
infrastructure to help promote reliability and reduce congestion.\30\ 
Congress further directed the Commission to ``exercise its authority'' 
under EPAct 2005 ``in a manner that facilitates the planning and 
expansion of transmission facilities to meet the reasonable needs of 
load-serving entities.'' \31\ Congress also gave the Commission certain 
``backstop'' transmission siting authority, and authorized the creation 
of interstate compacts establishing transmission siting agencies.\32\ 
EPAct 2005 also authorized the Commission to require unregulated 
transmitting utilities (except for certain small entities) to provide 
access to their transmission facilities on a comparable basis.\33\ 
Congress further ordered the Department of Energy (DOE) to study the 
benefits of economic dispatch and required the Commission to convene 
regional joint boards to develop a report to Congress containing 
recommendations for the use of security constrained economic dispatch 
within each region.\34\ Congress also directed the Commission to 
facilitate price transparency in markets for the sale and transmission 
of electric energy in interstate commerce, having due regard for the 
public interest, the integrity of those markets, fair competition, and 
the protection of consumers, and it authorized the Commission to 
prescribe rules to provide for the dissemination of information about 
the availability and price of wholesale electric energy and 
transmission service.\35\ Finally, Congress emphasized compliance with 
the Commission's regulations, increasing the civil and criminal 
penalties for violations of Commission-administered statutes and 
regulations.\36\
---------------------------------------------------------------------------

    \29\ See supra note 6.
    \30\ EPAct 2005 sec. 1241 (to be codified at section 219 of the 
FPA, 16 U.S.C. 824s).
    \31\ EPAct 2005 sec. 1233(a) (to be codified at section 
217(b)(4) of the FPA, 16 U.S.C. 824q).
    \32\ EPAct 2005 sec. 1221(a) (to be codified at section 216 of 
the FPA, 16 U.S.C. 824p).
    \33\ EPAct 2005 sec. 1231 (to be codified at section 211A of the 
FPA, 16 U.S.C. 824j-1).
    \34\ EPAct 2005 sec. 1234 (to be codified at 42 U.S.C. 16432); 
EPAct 2005 sec. 1298 (to be codified at section 223 of the FPA, 16 
U.S.C. 824w). EPAct 2005 defined economic dispatch as ``the 
operation of generation facilities to produce energy at the lowest 
cost to reliably serve consumers, recognizing any operational limits 
of generation and transmission facilities.'' EPAct 2005 sec. 1234 
(b).
    \35\ EPAct 2005 sec. 1281 (to be codified at section 220 of the 
FPA, 16 U.S.C. 824t).
    \36\ EPAct 2005 sec. 1284(d) (to be codified at section 316 of 
the FPA, 16 U.S.C. 825o); EPAct 2005 sec. 1284(e) (to be codified at 
section 316A of the FPA, 16 U.S.C. 825o-1).
---------------------------------------------------------------------------

    19. Recognizing the need for reform of Order No. 888 in light of 
these developments and those described in the next section, the 
Commission issued an NOI in September 2005 seeking comments on the 
reforms needed to the Order No. 888 pro forma OATT to prevent undue 
discrimination and preference in the provision of transmission 
services. In the NOI, the Commission expressed its preliminary view 
that reforms to the pro forma OATT and public utilities' OATTs are 
necessary to avoid undue discrimination or preference in the provision 
of transmission service. The NOI sought comments on how best to 
accomplish the Commission's goals, specifically with respect to 
enhancements that are needed to: (1) Remedy any unduly discriminatory 
or preferential application of the pro forma OATT or (2) improve the 
clarity of the Order No. 888 pro forma OATT and the individual public 
utility tariffs in order to more readily identify violations and 
facilitate compliance.
    20. The Commission received over 4,000 pages of initial and reply 
comments on the NOI. Based on these comments, the comments submitted in 
response to the ATC NOI, our experience in implementing Order No. 888, 
and the changes in the industry since we adopted it, we conclude that 
reform of the pro forma OATT is necessary, for the reasons we discuss 
next.

III. The Need for Reform of Order No. 888

A. Opportunities for Undue Discrimination Continue To Exist

    21. In Order No. 2000, the Commission found that ``opportunities 
for undue discrimination continue to exist that may not be remedied 
adequately by [the] functional unbundling [remedy of Order No. 888].'' 
\37\ The Commission made a similar finding in Order No. 2003, holding 
that opportunities for undue discrimination continue to exist in areas 
where the pro forma OATT leaves transmission providers with substantial 
discretion.\38\ The Commission has a responsibility under section 206 
of the FPA to remedy undue discrimination.\39\ Our action today 
proposes to fulfill that responsibility by proposing reforms to the pro 
forma OATT that will address remaining opportunities for undue 
discrimination.
---------------------------------------------------------------------------

    \37\ Order No. 2000 at 31,105.
    \38\ Order No. 2003 at P 11-12.
    \39\ In Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. 
Cir. 1987), (AGD), the court concluded that, like the Natural Gas 
Act, the FPA ``fairly bristles'' with concern over undue 
discrimination. Based on AGD, the Commission determined in Order No. 
888 that:
    The Commission has a mandate under sections 205 and 206 of the 
FPA to ensure that, with respect to any transmission in interstate 
commerce or any sale of electric energy for resale in interstate 
commerce by a public utility, no person is subject to any undue 
prejudice or disadvantage. We must determine whether any rule, 
regulation, practice or contract affecting rates for such 
transmission or sale for resale is unduly discriminatory or 
preferential, and must prevent those contracts and practices that do 
not meet this standard. * * * AGD demonstrates that our remedial 
power is very broad and includes the ability to order industry-wide 
non-discriminatory open access as a remedy for undue discrimination.
    Order No. 888 at 31,669.
---------------------------------------------------------------------------

    22. As the Commission noted in Order No. 888, it is in the economic 
self-interest of transmission monopolists, particularly those with 
high-cost generation assets, to deny transmission or to offer 
transmission on a basis that is inferior to that which they provide 
themselves.\40\ Such an incentive can lead to unduly discriminatory 
behavior

[[Page 32641]]

against third parties, particularly if public utilities have 
unnecessarily broad discretion in the application of their tariffs. 
This discretion also can create problems for transmission providers 
seeking to comply with our regulations in good faith because so many 
issues are left for their interpretation, thereby increasing the 
possibility of disputes with transmission customers and enforcement 
actions by the Commission.\41\ Transmission customers also have found 
ways to use the tariffs to their own advantage, particularly in the 
scheduling and queuing processes.\42\ Finally, tariff provisions have 
been modified in numerous ways on a company-by-company basis, leading 
to uncertainties within the industry as to the proper interpretation of 
those provisions and to unnecessarily inconsistent treatment of 
transmission customers across public utilities.
---------------------------------------------------------------------------

    \40\ Id. at 31,682.
    \41\ See, e.g., Order No. 2003 at P 11-12.
    \42\ See, e.g., Potomac Economics, Ltd., 2004 State of the 
Market Report: Midwest ISO at 30-31, 34-35 (Jun. 2005) (explaining 
that the queuing process, by giving customers the opportunity to 
submit multiple requests for service, provides a low or no-cost 
option that restricts other customers' access to congested 
interfaces, and the scheduling process, by allowing customers to 
leave transmission requests unconfirmed, provides a free option that 
may invite hoarding or result in underutilized capacity), http://www.midwestmarket.
 org/publish/Document/2b8a32-- 103ef711180---

7bf20a48324a /2004%20MISO%20SOM%20Report. pdf?action=download&--
property=Attachment.
---------------------------------------------------------------------------

    23. Commenters suggest that enhanced clarity and consistency in the 
pro forma OATT would go a long way toward eliminating the opportunities 
for undue discrimination and the perception that it is occurring.\43\ 
Calpine notes that undue discrimination is most likely to occur when 
the transmission provider retains discretion to implement an OATT 
provision in a manner that favors its affiliated generation. APPA 
asserts that the success of the OATT regime depends on public 
utilities' ability to faithfully implement the OATT's provisions. Large 
transmission providers share this view to some degree. Entergy notes 
that a lack of clarity is at the heart of many disputes involving the 
OATT, and urges the Commission to improve the OATT in a manner that 
will minimize the potential for future violations. Duke posits that 
tariff terms and conditions that are susceptible to multiple 
interpretations present opportunities for discrimination and/or the 
perception thereof. Progress Energy agrees that several OATT provisions 
can be interpreted differently, leaving room for disagreement as to 
their meaning.
---------------------------------------------------------------------------

    \43\ E.g., Calpine, Duke, and MidAmerican. (A list of commenter 
acronyms may be found in Appendix A). As the Commission noted in 
Order No. 2000, ``[p]erceptions of discrimination are significant 
impediments to competitive markets. Efficient and competitive 
markets will develop only if market participants have confidence 
that the system is administered fairly.'' Order No. 2000 at 31,017.
---------------------------------------------------------------------------

    24. Perhaps the most obvious deficiency in this regard is ATC 
calculation. In Order Nos. 888 and 889, the Commission declined to 
require a specific methodology for ATC calculation. As a result, there 
are few clear rules respecting ATC calculation, and transmission 
providers, therefore, retain unnecessarily broad discretion in this 
area. On systems where transmission capacity is congested, this lack of 
consistency, coupled with a lack of transparency, has led to recurring 
disputes over whether the transmission provider is exercising its 
discretion to discriminate against its competitors.
    25. There is a similar lack of clarity in the transmission 
provider's planning obligations. Order No. 888 included a general 
obligation on the part of the transmission providers to plan on a 
comparable basis (i.e., comparable to the manner in which it would plan 
for its own needs) to serve network loads and to construct new 
facilities as necessary to respond to requests for firm service from 
point-to-point customers. However, there were no clear guidelines with 
respect to whether transmission customers should be included in the 
planning process, what standards and criteria should be used in system 
planning, and whether the planning process should identify potential 
economic upgrades that could benefit a wide range of customers, as 
opposed to responding only to customer-specific requests. Here too, 
this lack of clarity has led to significant disputes over whether 
transmission providers are planning on a nondiscriminatory basis or are 
favoring service to their own loads.

B. A Lack of Transparency Undermines Confidence in Open Access and 
Impedes Enforcement of Open Access Requirements

    26. A major focus of comments on the NOI is that increased 
transparency would aid transmission customers in their participation in 
the wholesale market.\44\ Constellation explains that the transmission 
provider's unique position as the owner and operator of the 
transmission system and often the majority of the generation assets in 
its control area gives it better information than its transmission 
customers. Moreover, the transmission provider, Constellation argues, 
has financial incentives to use the system differently, and more 
efficiently, to serve its own loads than to serve its other customers 
under the pro forma OATT. TDU Systems urges the Commission to ensure 
that transmission providers make their actions under the OATT 
completely transparent on a timely basis to all transmission customers. 
NARUC posits that enhanced reporting requirements, if sufficiently 
targeted, would facilitate greater transparency in transmission 
activities. Alberta Intervenors states that the current pro forma OATT 
provides transmission customers with only a narrow glimpse of how the 
system is being operated. For example, Bonneville notes that many terms 
and conditions of native load service are not transparent to OATT 
transmission customers.\45\ EEI also states that greater transparency, 
such as with respect to ATC calculation, can increase confidence in 
open access and potentially reduce claims of undue discrimination.
---------------------------------------------------------------------------

    \44\ E.g., LG&E, MidAmerican, Midwest SATs, TDU Systems, and 
Williams.
    \45\ Bonneville urges the Commission to require load-serving 
transmission providers to post the same information for bundled 
retail load that they must post for service to network customers.
---------------------------------------------------------------------------

    27. Calpine argues that undue discrimination is difficult to detect 
given the lack of access to data, analytical assumptions, and processes 
used by transmission providers to determine transmission access and 
service. It recommends that the Commission increase reporting 
requirements for denials of transmission service, for congestion 
management mitigation events, including curtailments and redispatch, 
and for transmission expansion planning decisions. Powerex notes that 
the Commission already has posting standards, and urges the Commission 
to enforce them and to increase requirements to provide more meaningful 
posting of reliable ATC data, curtailment methodology and results, 
details relating to denials of service, and congestion information. 
Constellation agrees, urging the Commission to require OASIS posting of 
service metrics, such as all transmission requests approved, rejected, 
confirmed and curtailed.
    28. A common theme in the comments is that the lack of transparency 
can lead to claims of undue discrimination and can make such claims 
more difficult to resolve.\46\ As such, National Grid asserts that 
greater transparency will allow the Commission and transmission system 
users to understand when a transmission access decision is

[[Page 32642]]

motivated by a legitimate reason rather than an intent to discriminate. 
If transmission customers have more accurate information about the 
transmission service request process, National Grid contends, they also 
will have more accurate expectations and a better understanding of how 
to expedite the implementation of service. Though NRECA agrees that 
increased transparency will allow the Commission to deter undue 
discrimination and facilitate accountability, it urges the Commission 
to require not just raw data but meaningful, clear and understandable 
data, in a format that facilitates understanding.
---------------------------------------------------------------------------

    \46\ E.g., Ameren, National Grid, and NRECA.
---------------------------------------------------------------------------

    29. Commenters urge the Commission to improve the transparency of 
transmission service in a number of areas, particularly the evaluation 
of ATC and the planning of the transmission system.\47\ Another area 
often cited as lacking sufficient transparency is the processing of 
transmission service requests and studies. For example, several 
commenters note that system impact studies are often not completed 
within the tariff-prescribed time limits, and that information about 
that process is not available to transmission customers.\48\ TDU 
Systems suggests that one way to address the difficulty of determining 
acceptable delays is to require transmission providers to post 
statistics on their OASIS sites providing information as to the length 
of time it might take to process requests for transmission service. 
Cinergy proposes that adopting such reporting metrics could result in 
an improved quality of service.
---------------------------------------------------------------------------

    \47\ We discuss these specific aspects of the pro forma OATT 
below in Parts V.A. and V.B.
    \48\ E.g., Constellation, EPSA, Powerex, and Williams.
---------------------------------------------------------------------------

    30. We agree that a lack of transparency both increases the 
potential for undue discrimination and makes it more difficult to 
detect. We believe this lack of sufficient transparency is caused in 
part by inadequate compliance with our existing OASIS regulations, and 
in part by inadequate transparency requirements. Our reforms address 
both elements of the problem in an effort to increase confidence in 
open access tariffs and to facilitate compliance with our regulations 
and our enforcement of them.

C. Congestion and Inadequate Infrastructure Development Impede 
Customers' Use of the Grid

    31. The ability and incentive to discriminate increases as the 
transmission system becomes more congested. Vertically integrated 
utilities do not have an incentive to expand the grid to accommodate 
new entry or to facilitate the dispatch of more efficient competitors. 
Even with the advent of RTOs, transmission infrastructure development 
has not kept pace with the increase in demand for electricity. 
Transmission capacity is being constructed at a much slower rate than 
the rate of increase in customer demand. Indeed, transmission capacity 
per MW of peak demand declined at an average rate of 2.1 percent per 
year during the period 1992 to 2002.\49\ Investment for the most recent 
year available, 2003, was below 1975 levels,\50\ and projections 
suggest that this trend will continue through 2012.\51\ As a result, 
there has been a significant decrease in transmission capacity relative 
to load in every NERC region.\52\ EEI estimates that capital spending 
must increase by 25 percent, from $4 billion annually to $5 billion 
annually, to ensure system reliability and to accommodate wholesale 
electric markets.\53\ The legacy systems constructed by vertically 
integrated utilities prior to the adoption of Order No. 888 support 
``only limited amounts of inter-regional power flows and transactions. 
Thus, existing systems cannot fully support all of society's goals for 
a modern electric-power system.'' \54\ These systems were built to meet 
the vertically integrated utilities' retail native load obligations, 
not to support the development of a bulk power market.
---------------------------------------------------------------------------

    \49\ Eric Hirst, U.S. Transmission Capacity: Present Status and 
Future Prospects (Aug. 2004), available at http://www.eei.org/industry_issues/energy_infrastructure/transmission/USTransCapacity10-18-04.pdf
 (Present Status and Future Prospects).

    \50\ EEI, EEI Survey of Transmission Investment: Historical and 
Planned Capital Expenditures (1999-2008) at 3 (May 2005), available 
at http://www.eei.org/industry_issues/energy_infrastructure/transmission/Trans_Survey_Web.pdf
.

    \51\ Present Status and Future Prospects at v.
    \52\ Brendan Kirby (Oak Ridge National Laboratory, U.S. 
Department of Energy, Barriers to Transmission Investment, Technical 
Conference Presentation, (Docket No. AD05-5-000) (April 22, 2005) 
Transmission Independence and Investment.
    \53\ Energy Policy Act of 2005: Hearings before the House 
Subcommittee on Energy and Commerce, 109th Congress, First Sess. 
(2005) (Prepared statement of Thomas R. Kuhn, President of EEI).
    \54\ Present Status and Future Prospects at v.
---------------------------------------------------------------------------

    32. Inadequate expansion of the transmission grid has contributed 
to increasing transmission congestion in most regions of the country. 
Transmission congestion has created fairly small local load pockets in 
primarily urban areas, e.g., New York City, Long Island, Boston, parts 
of Connecticut, and the San Francisco Bay Area. Other load pocket 
concerns have arisen in parts of northern Virginia, and various load 
centers in SPP. Still other constraints are more regional in scope: (1) 
From the Midwest to the Mid-Atlantic, (2) from the Midwest to the 
Tennessee Valley Authority (TVA), (3) into and within California, (4) 
from TVA and Southern into Entergy, (5) from Mid-America Interconnected 
Network into Wisconsin-Upper Michigan Systems, and (6) into Florida. 
The existence of these and other constraints affecting transmission 
systems can result in an increase in the frequency of denials of 
requests for transmission service, and an increase in the frequency of 
transmission service interruptions and/or curtailments of transmission 
service. While not all congestion needs to be remedied (i.e., if the 
cost of the congestion is less than the cost to relieve it), it is also 
true that undue discrimination and preferential treatment also are much 
more difficult to detect when the transmission grid is constrained, 
given the lack of transparency in ATC calculations and transmission 
system planning. Increased congestion also presents additional 
opportunities for undue discrimination. As a result, it is more 
difficult for the Commission to carry out its statutory responsibility 
to ensure that transmission providers provide nondiscriminatory open 
access transmission service.
    33. In recognition of the lack of adequate infrastructure, a broad 
cross-section of the industry supports greater coordination in the 
planning and investment in transmission infrastructure between 
transmission providers, transmission customers and state regulatory 
agencies. A major focus of comments on our NOI was the need to plan and 
build infrastructure to facilitate regional electricity markets. For 
example, AEP argues that the most important issue faced by public 
utilities and their customers is not day-to-day OATT administration but 
the planning and expansion of the transmission grid. EEI likewise 
asserts that the focus should be on the need to develop energy 
infrastructure necessary to facilitate growth in wholesale electric 
market transactions. Santa Clara acknowledges that lack of needed 
infrastructure causes the grid to become constrained and less reliable, 
which sometimes provides even stronger incentives for owners to 
restrict access by others. The Nevada Companies urge the Commission to 
focus on ways Order No. 888 and the pro forma OATT can be revised to 
eliminate disincentives to the construction of additional transmission 
facilities. Xcel suggests that the

[[Page 32643]]

Commission focus its efforts on ways to encourage investment in new 
energy infrastructure as a way of easing congestion and enabling growth 
in market transactions. Salt River contends that the Commission should 
increase incentives to participate in long-term regional planning 
processes. Midwest SATs argue that increased access for all 
transmission system users through policies that promote investment in 
transmission will do more to reduce undue discrimination than policies 
that seek to uncover and penalize such discrimination.
    34. Customers also complain that there is often a lack of 
transparency in utility transmission planning processes, which the 
customers claim typically do not include economic system upgrades that 
would benefit non-affiliate users of the system. Customers also note 
the lack of clarity in the existing planning obligations required of 
transmission providers. They assert that these failures have 
contributed to the inadequate development of the transmission grid.
    35. Order No. 888 contemplated that ISOs would enhance 
infrastructure development through open and regional planning 
processes, but these efforts have stalled in many regions of the 
country. Even where RTOs have been established, there have been 
concerns that the planning process has not always been sufficiently 
robust, inclusive or transparent to ensure that transmission investment 
occurs where it is reasonably needed for all users of the grid. For 
example, in its reply comments, TDU Systems urges the Commission to 
include RTOs in its planning reforms, contending that many RTO planning 
processes are not open to all stakeholders, nor are they collaborative 
and inclusive. Many commenters argue that RTO transmission planning 
regimes have failed to get needed transmission facilities built.\55\
---------------------------------------------------------------------------

    \55\ E.g., APPA, TDU Systems Reply Comments, and Williams Reply 
Comments.
---------------------------------------------------------------------------

    36. We conclude that the inadequacy of the existing obligation to 
conduct joint and regional transmission system planning, coupled with 
the lack of transparency surrounding system planning generally, require 
reform of the pro forma OATT to ensure that transmission infrastructure 
is constructed on a nondiscriminatory basis and is otherwise sufficient 
to support reliable and economic service to all eligible customers.

D. A Consistent Method of Measuring ATC Has Not Been Established

    37. Under Order No. 888, each public utility calculates the amount 
of transfer capability on its system that is available for sale to 
third parties.\56\ However, Order No. 888 did not require that the 
methodology for ATC calculation be standardized across the industry, 
nor did it impose any specific requirements regarding the disclosure of 
the methodologies used by each transmission provider. As a result, 
there are a variety of ATC calculation methodologies in use today. 
Moreover, there is often very little transparency regarding the nature 
of these calculations, given that many transmission providers have 
filed only summary explanations of their ATC methodologies in 
Attachment C to the OATT. As a result, transmission providers retain 
unnecessarily broad discretion in calculating ATC. The resulting 
discretion is a significant problem because calculation of ATC, which 
varies greatly depending on the criteria and assumptions used, may 
allow the transmission provider to discriminate in subtle ways against 
its competitors. This discretion, coupled with the lack of 
transparency, also hampers the detection of undue discrimination and, 
thereby, undermines the Commission's ability to enforce the general 
requirement in Order No. 888 that transmission service be provided on a 
not unduly discriminatory basis.\57\
---------------------------------------------------------------------------

    \56\ Order No. 888 at 31,794 n.610.
    \57\ APPA submitted comments in Docket No. RM05-17-000 arguing 
that the calculation and posting of ATC ``sits at the pivot point 
among reliability, economic regulation and wholesale electric 
commerce.'' APPA at 5.
---------------------------------------------------------------------------

    38. The comments on the NOI and the ATC NOI reflect these 
underlying problems. Many market participants complain that there is 
widespread misinformation regarding the actual ATC, which results in 
missed opportunities for transactions. ATC calculation errors often 
occur. A lack of transparency leaves transmission customers unaware of 
why some transmission requests are granted and others are denied.\58\ 
Several ATC inputs, such as the capacity benefit margin (CBM) or the 
transmission reliability margin (TRM), can be calculated using overly 
conservative or otherwise faulty assumptions. Transmission customers 
often complain that transmission providers designate unreasonably high 
CBM or TRM levels, which limits the amount of remaining transfer 
capability available for other users of the system.
---------------------------------------------------------------------------

    \58\ See, e.g., EEI at 18 (agreeing that the Commission should 
require transmission providers to make their ATC calculations more 
transparent).
---------------------------------------------------------------------------

    39. As a result of these uncertainties, the Commission issued the 
ATC NOI to address the lack of clear and consistent methodologies for 
calculating ATC. In the ATC NOI, the Commission acknowledged that NERC 
has been working on specific recommendations for calculating and 
coordinating ATC and available flowgate capability (AFC).\59\ That NERC 
effort culminated in a report and a number of recommendations. The 
Commission asked for comments on those recommendations, as well as 
comments on whether there should be common transmission calculation 
methodologies among regions. The Commission has reviewed those comments 
as part of this proceeding.\60\
---------------------------------------------------------------------------

    \59\ See NERC, Long-Term AFC/ATC Task Force Final Report (2005) 
(NERC Report) at 2, available at ftp://www.nerc.com/pub/sys/all_updl/mc/ltatf/LTATF_Final_Report_Revised.pdf
.

    \60\ Accordingly, we consolidate Docket No. RM05-17-000 with 
this proceeding. We will distinguish the comments received in the 
ATC NOI proceeding by the designation ``ATC NOI Comments.'' In 
addition, we also revise the name of the proceeding in Docket No. 
RM05-17-000 to ``Preventing Undue Discrimination and Preference in 
Transmission Service.''
---------------------------------------------------------------------------

    40. Many commenters support the development of a consistent, 
industry-wide methodology for calculating ATC.\61\ These commenters 
maintain that a requirement that all transmission providers use the 
same methodology to determine ATC would not only remedy the lack of 
clarity that surrounds these calculations and reservations, but would 
provide regulatory certainty and assist transmission customers in 
predicting the outcome of transmission service requests.
---------------------------------------------------------------------------

    \61\ E.g., Alcoa, AWEA, Constellation, Exelon, Occidental, and 
Renewable Energy.
---------------------------------------------------------------------------

    41. We agree. Although the industry has sought to pursue greater 
consistency in ATC calculations through existing NERC processes, those 
efforts to date have been largely unsuccessful. The lack of a 
consistent, industry-wide methodology for calculating ATC gives 
transmission providers the ability and the opportunity to unduly 
discriminate against third parties. We therefore propose below a number 
of reforms to the process of calculating ATC to provide clarity and 
transparency to users of the grid.

E. A Number of Transmission Pricing Policies May Impede the Use of the 
Grid

    42. Transmission customers often complain about the level and scope 
of imbalance charges that are levied under the pro forma OATT and under 
individual interconnection agreements.

[[Page 32644]]

Energy imbalance charges, including penalties on some systems, are 
imposed on a transmission customer when the amount of energy scheduled 
for delivery to the transmission grid does not equal the amount of 
energy withdrawn by that customer. Customers complain that these 
charges are excessive and not related to the actual costs incurred by 
transmission providers. They also argue that the inconsistency between 
these charges in different control areas is unnecessary, and that other 
means of compensating the transmission provider, such as return-in-
kind, should be considered. Generator imbalance charges are levied on 
generators for deviations between the amount of energy they schedule 
and the amount they actually deliver to the grid. Generators likewise 
complain that these charges are excessive, that transmission providers 
refuse to credit generators with the revenues resulting from imbalance 
penalties that are collected, and that transmission providers prevent 
unaffiliated generators from purchasing or self-supplying generator 
imbalance services. In addition, owners of intermittent resources 
complain that generator imbalance penalties, which are imposed to 
provide an incentive for generators to schedule accurately, are 
inappropriate given their lack of control and ability to cure 
deviations.
    43. Transmission providers and customers raise a number of concerns 
related to the pricing of transmission service under Order No. 888, 
contending that the Commission's pricing policies are in need of 
reform. For example, under the pro forma OATT, network customers can 
receive a credit toward their transmission charges for new facilities 
that they jointly plan with the transmission provider. Customers 
contend that this provision actually acts as a disincentive for joint 
planning because transmission providers can avoid granting credits if 
they fail to jointly plan with their transmission customers.
    44. Finally, there is also concern about the appropriate rate for 
transmission capacity that has been resold by the original transmission 
customer. Under Order No. 888, such capacity may be priced at the 
higher of the original rate, the transmission provider's maximum stated 
firm rate, or the assignor's opportunity costs capped at the cost of 
expansion. Customers complain that this policy does not work when 
opportunity costs exceed the embedded cost rate, because the assignor 
must make a FPA section 205 filing with the Commission that estimates 
its opportunity cost over the term of the reassignment as well as the 
cost of system expansion. The time and effort required to complete the 
regulatory process appears to inhibit such reassignments.
    45. Although Order No. 888 was primarily directed at establishing 
the non-rate terms and conditions of open access, the rule did adopt 
certain pricing policies that were associated with the form of open 
access being ordered. After reviewing the comments, we believe certain 
reforms are appropriate because some of the pricing policies associated 
with the pro forma OATT are no longer just and reasonable or are 
otherwise unduly discriminatory. However, we do not intend to pursue 
generic reform of other pricing policies that are better addressed on a 
region-or case-specific basis, such as the pricing of new transmission 
facilities.

F. EPAct 2005 Emphasized Certain Policies and Priorities for the 
Commission

    46. The reforms we propose today also are consistent with the 
policies and priorities embodied in EPAct 2005, in which Congress 
emphasized many of the principles reflected in this NOPR.
    47. First, Congress in EPAct 2005 placed special emphasis on the 
development of transmission infrastructure. Congress required the 
Commission to adopt a rule establishing incentive-based rates for new 
transmission infrastructure investment. The stated purpose of new FPA 
section 219 is to benefit ``consumers by ensuring reliability and 
reducing the cost of delivered power by reducing transmission 
congestion.'' \62\ FPA section 219 requires the Commission to 
``promot[e] capital investment in the enlargement, improvement, 
maintenance, and operation of all facilities for the transmission of 
electric energy in interstate commerce, regardless of the ownership of 
the facilities.'' \63\ Congress also gave the Commission certain 
``backstop'' transmission siting authority, and authorized the creation 
of interstate compacts establishing transmission siting agencies.\64\ 
Finally, the Commission was directed to ``exercise its authority'' 
under EPAct 2005 ``in a manner that facilitates the planning and 
expansion of transmission facilities to meet the reasonable needs of 
load-serving entities to satisfy the service obligations of the load-
serving entities, 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.'' \65\ 
Although these provisions are, or will be, addressed primarily in other 
proceedings, our NOPR is consistent with these provisions because it 
supports new infrastructure by reforming the transmission planning 
process to ensure that it is open, transparent and 
nondiscriminatory.\66\
---------------------------------------------------------------------------

    \62\ EPAct 2005 sec. 1241 (to be codified at section 219 of the 
FPA, 16 U.S.C. 824s). The Commission issued a NOPR implementing such 
an incentive rate program in November 2005. See Promoting 
Transmission Investment through Pricing Reform, 70 FR 71409 (Nov. 
29, 2005), FERC Stats. & Regs. ] 32,593 (2005).
    \63\ FPA Sec. 219(b)(1).
    \64\ EPAct 2005 sec. 1221(a) (to be codified at section 216 of 
the FPA, 16 U.S.C. 824p).
    \65\ EPAct 2005 sec. 1233(a) (to be codified at section. 
217(b)(4) of the FPA, 16 U.S.C. 824q).
    \66\ We note that we also have proposed to implement FPA section 
217(b)(4) in a separate rulemaking in Docket No. RM06-8-000.
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    48. Second, Congress emphasized the need for greater transparency 
in electricity markets, including transmission service. EPAct 2005 
added section 220 to the FPA, which requires the Commission to 
facilitate ``price transparency in markets for the sale and 
transmission of electric energy in interstate commerce, having due 
regard for the public interest, the integrity of [that market], fair 
competition, and the protection of consumers.'' \67\ The Commission was 
authorized to ``prescribe such rules as the Commission determines 
necessary and appropriate to carry out the purposes of'' FPA section 
220. Those rules ``shall provide for the dissemination, on a timely 
basis, of information about the availability and prices of wholesale 
electric energy and transmission service to the Commission, State 
commissions, buyers and sellers of wholesale electric energy, users of 
transmission services, and the public.'' Our NOPR similarly seeks to 
promote greater transparency in the provision of transmission service 
in many important areas, including ATC calculation and transmission 
planning.
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    \67\ EPAct 2005 sec. 1281 (to be codified at 16 U.S.C. 824t).
---------------------------------------------------------------------------

    49. Finally, Congress emphasized compliance with the Commission's 
regulations, increasing the civil and criminal penalties for violations 
of Commission-administered statutes and regulations.\68\ This new 
authority buttresses the Commission's efforts to enforce public utility 
OATTs and the regulations requiring transmission information to be 
posted on OASIS. As we explained in the Enforcement Policy Statement, 
however, this new authority carries with it the responsibility to 
ensure that enforcement is firm but fair and that our rules are as 
clear as

[[Page 32645]]

practicable to facilitate compliance.\69\ The NOPR is fully consistent 
with these principles because it seeks, in many areas, to clarify our 
rules to facilitate compliance by transmission providers.
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    \68\ EPAct 2005 sec. 1284(e)(1) (to be codified at section 
316(A) of the FPA, 16 U.S.C. 825o-1 (2000).
    \69\ Enforcement of Statutes, Orders, Rules and Regulations, 
Policy Statement on Enforcement, 113 FERC ] 61,068 (2005) 
(Enforcement Policy Statement).
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IV. Summary, Scope and Applicability of the Proposed Rule

    50. This section provides: (1) A summary of the major components of 
the NOPR, (2) a description of the core elements of Order No. 888 that 
we propose to retain, and (3) a discussion of the applicability of the 
proposed rule to various entities.

A. Summary of Proposed Reforms

    51. Consistency and transparency of ATC calculations. The 
Commission finds that the lack of a consistent, industry-wide 
methodology for calculating ATC, and the lack of adequate transparency 
in ATC calculations, increases the potential for undue discrimination 
and also makes undue discrimination more difficult to detect. The lack 
of consistent standards can facilitate undue discrimination by giving a 
transmission provider the discretion, and hence the ability and 
opportunity, to favor itself and its affiliates over third parties in 
how it calculates and allocates ATC and, therefore, may be unjust, 
unreasonable, unduly discriminatory and preferential. As a result, we 
propose to give the industry specific guidance and a firm deadline to 
develop certain requirements to make the process of calculating ATC and 
the process of exchanging data between transmission providers about ATC 
more consistent. In addition, we propose to amend pro forma OATT 
requirements as well as our OASIS regulations to increase the 
transparency in how ATC is calculated.
    52. Requirement for coordinated, open and transparent transmission 
planning. The Commission finds that Order No. 888 does not contain 
sufficient protections to guard against undue discrimination in 
transmission system planning. This, in turn, can affect a customer's 
ability to obtain transmission service and the price it pays for 
transmission. Specifically, Order No. 888 does not require sufficient 
coordination, openness, and transparency in transmission planning to 
ensure that new infrastructure is constructed to meet the needs of all 
eligible customers on a not unduly discriminatory basis. Without 
adequate coordination and open participation, market participants have 
minimal input or insight into whether a particular transmission plan 
treats all loads and generators comparably. To ensure that truly 
comparable transmission service is provided by all public utility 
transmission providers, including RTOs and ISOs, we propose to amend 
the pro forma OATT to require coordinated, open, and transparent 
transmission planning on both a sub-regional and regional level. To 
implement this remedy, we propose eight planning principles that each 
public utility transmission provider will be required to follow. We 
recognize that many regions have made significant progress in recent 
years in creating greater openness and transparency in transmission 
planning and believe our proposed reforms will build upon, strengthen, 
and improve this progress to reform transmission planning.
    53. Transmission Pricing Reforms. Consistent with the focus of 
Order No. 888 on the non-rate terms and conditions of open access, the 
Commission does not intend to initiate broad reform of transmission 
pricing policy through this NOPR. However, we have identified several 
pricing rules that are part and parcel of OATT service that merit 
reform.
     Energy and Generator Imbalance Charges. We find that 
existing energy and generator imbalance charges may be excessive and 
otherwise unrelated to the cost of providing the service and, 
therefore, propose to reform energy and generator imbalance pricing. We 
propose to require that all such imbalance charges meet the following 
criteria: The charges must (1) be related to the cost of correcting the 
imbalance, (2) be tailored to encourage accurate scheduling behavior, 
such as by increasing the percentage of the adder as the deviations 
become larger, and (3) account for the special circumstances presented 
by intermittent generators, such as by waiving the higher ends of the 
deviation penalties.
     Capacity Reassignment Pricing. We find that the existing 
cap on the reassignment of point-to-point service may no longer be just 
and reasonable and, therefore, propose to eliminate the cap. We believe 
that removing the cap will eliminate an unnecessary impediment to the 
resale of capacity, which in turn should increase utilization of the 
grid and otherwise ensure that point-to-point service is just, 
reasonable and not unduly discriminatory. We seek comment on this 
proposal and, in particular, the nature of the reporting obligations 
that should be imposed as part of lifting the cap on reassignment.
     Crediting of Customer-Owned Facilities. We propose to 
retain most elements of our existing policy respecting the crediting of 
customer-owned facilities, including the requirement that such 
facilities meet the integration standard. However, we propose to 
eliminate the requirement that new facilities can receive credits only 
if they are ``jointly planned'' because this requirement may provide a 
disincentive to coordinated planning. Rather, we propose that such new 
facilities be eligible for credits if: (1) Such facilities are 
integrated into the operations of the transmission provider's 
facilities, and (2) such facilities would be eligible for inclusion in 
the transmission provider's annual transmission revenue requirement if 
owned by the transmission provider.
    54. Improvements to Point-to-Point Service. The Commission 
concludes that the existing methods for evaluating requests for long-
term firm point-to-point service may no longer be just, reasonable and 
not unduly discriminatory. When a transmission provider considers a new 
resource to serve native load, the transmission provider does not 
eliminate an otherwise economic option because the resource may not be 
deliverable in a few hours of the year. For transmission customers, 
however, the transmission provider evaluates whether service can be 
granted in every hour of the year that is modeled and, if not, it 
informs the customer that service cannot be provided out of existing 
transfer capability. Only if the transmission customer agrees to pay 
for time-consuming and costly facilities studies does the transmission 
provider evaluate redispatch options, including whether they are less 
expensive than the upgrade options. The Commission proposes to address 
this problem by clarifying that a transmission provider must use all of 
its available redispatch options to satisfy a request for firm point-
to-point service and, at the transmission customer's option, these 
redispatch options must be studied before the customer is obligated to 
incur the costs and time delays associated with a facilities study. The 
Commission also seeks comment on whether this remedy is adequate or, 
alternatively, whether the Commission should modify the nature of 
point-to-point service to require that transmission providers offer a 
``conditional firm'' service that would be subject to curtailment prior 
to firm service only a limited number of hours of the year.
    55. Reform of rollover rights. The Commission concludes that 
section 2.2 of the pro forma OATT, which grants an

[[Page 32646]]

ongoing right to transmission customers to renew or ``rollover'' their 
contracts, is in need of reform. The Commission proposes to revise that 
provision to apply to contracts that have a minimum term of five years, 
rather than the current minimum term of one year. We conclude that this 
reform will ensure that the rollover right is enjoyed by transmission 
customers that have made a significant commitment to (and investment 
in) the transmission grid. In addition, the Commission proposes that a 
transmission customer eligible for rollover rights must provide notice 
of whether or not it will exercise its right of first refusal to renew 
the contract no less than one year prior to the expiration date of the 
transmission service agreement, rather than within the current 60-day 
period.
    56. Increases in transparency to lessen the opportunities to 
discriminate and reduce transaction costs. In addition to the increased 
transparency we propose to require regarding the calculation of ATC and 
transmission planning, we propose to increase the transparency of 
transmission service provided under the pro forma OATT in several other 
respects. For example, we propose to require transmission providers and 
their network customers to use the transmission provider's OASIS to 
request designation of a new network resource and to terminate the 
designation of an existing network resource. In addition, we propose to 
require the transmission provider to modify its OASIS so that requests 
to designate and terminate a network resource can be queried. We also 
propose to require the transmission provider to post on its OASIS a 
list of its current designated network resources and all network 
customers' current designated network resources. Finally, we propose to 
require transmission providers to post on OASIS all their business 
rules, practices and standards that relate to transmission services 
provided under the pro forma OATT.
    57. Strengthening enforcement of the pro forma OATT. Our proposed 
reforms include several clarifications of the terms and conditions of 
the pro forma OATT that have made undue discrimination difficult to 
detect and otherwise frustrated enforcement of the obligation to 
provide open access, non-discriminatory transmission service. Our new 
civil penalty authority under EPAct 2005 gives us ample power to remedy 
tariff violations, but it also places upon us an increased 
responsibility to make the rules as clear as possible. In addition, we 
propose a number of posting and reporting requirements that will 
provide the Commission and market participants with information about 
each transmission provider's performance of pro forma OATT obligations. 
For example, we propose to require transmission providers to post 
specific performance metrics related to their completion of studies 
required under the pro forma OATT. We note that the Commission will 
continue to audit compliance with the pro forma OATT, and toward that 
end propose to require transmission information kept on OASIS to be 
retained for audit purposes for five years. Finally, we make a number 
of proposals relating to operational penalties assessed under the pro 
forma OATT, including so-called ``over-use'' penalties, and the 
treatment of operational penalty revenues collected from transmission 
providers and their affiliates.
    58. Miscellaneous OATT improvements. We propose a number of 
improvements to the terms and conditions of the pro forma OATT to 
incorporate the lessons learned over the past ten years. We briefly 
note these below:
    Hourly Firm. We propose to require transmission providers to offer 
hourly firm service under the pro forma OATT.
    Designation of network resources. We propose to make a number of 
clarifications related to the types of agreements that may be 
designated as network resources, the process for verifying whether 
agreements meet the requirements in the pro forma OATT, and the 
requirement for transmission providers to designate and undesignate 
network resources. We also propose to require customers to submit an 
attestation with each application to designate a new network resource.
    Reservation priorities. We propose to change the priority rules to 
give priority to pre-confirmed transmission service requests submitted 
in the same time period. We also propose to add price as a tie-breaker 
in determining reservation queue priority when the transmission 
provider is willing to discount transmission service.
    Clarifications related to network service. We propose to clarify 
that a network customer may not use secondary network service to bring 
energy onto its system to support an off-system sale if the purchased 
power does not displace the customer's own higher cost generation. We 
also propose clarifications related to use of network service on an 
``as available basis'' and to ``redirects'' of network service.
    Definitions. In addition to some minor revisions, we propose to add 
a definition of ``non-firm sales'' to the pro forma OATT and propose to 
amend the definition of Good Utility Practice to reference the 
definition of ``reliable operation'' adopted in EPAct 2005.

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

    59. Although we are proposing many important reforms to Order No. 
888 and the pro forma OATT, we also wish to emphasize that we propose 
to retain many of the core elements of Order No. 888. We note that many 
of these core elements enjoy broad support across many sectors of the 
industry. In their comments, APPA, EEI, and NARUC urge the Commission 
to proceed carefully in reforming Order No. 888, focusing on 
incremental reforms not industry restructuring. We share the view that 
Order No. 888 can be strengthened without discarding its fundamental 
structure. We discuss below the core elements that are being retained 
and, where appropriate, respond to the comments on these points that 
were received in the NOI.
1. Federal/State Jurisdiction
    60. In Order No. 888, the Commission stated that it has exclusive 
jurisdiction over the rates, terms and conditions of unbundled retail 
transmission in interstate commerce.\70\ Though the Commission adopted 
a test for determining which facilities were used for retail 
transmission, as opposed to local distribution to end-users,\71\ the 
Commission stated that it generally would defer to determinations by 
state regulatory authorities concerning where to draw the 
jurisdictional line under that test.\72\ The Commission declined to 
assert jurisdiction over bundled retail transmission, reasoning that 
``when transmission is sold at retail as part and parcel of the 
delivered product called electric energy, the transaction is a sale of 
electric energy at retail.'' \73\ The U.S. Supreme Court affirmed the 
Commission's decision to assert jurisdiction over unbundled but not 
bundled retail transmission, finding that the Commission made a 
statutorily permissible choice.\74\
---------------------------------------------------------------------------

    \70\ Order No. 888 at 31,781.
    \71\ Id. at 31,771 (setting forth the seven-factor test).
    \72\ Id. at 31,781.
    \73\ Id.
    \74\ See New York v. FERC, 535 U.S. 1, 28 (2002).
---------------------------------------------------------------------------

    61. We propose to retain the jurisdictional divide we established 
in Order No. 888. We also are mindful of the need for heightened 
cooperation between federal and state regulators in areas where there 
are overlapping federal and state policy concerns. Moreover, our 
jurisdictional determination was sustained by the U.S.

[[Page 32647]]

Supreme Court and has been accepted by industry and state regulatory 
authorities. We see no reason to disturb that determination now.
2. Native Load Protection
    62. Order No. 888 did not require transmission providers to 
unbundle transmission service to their retail native load nor did it 
require that bundled retail service be taken under the terms of the pro 
forma OATT.\75\ Moreover, the Commission allowed a transmission 
provider to reserve, in its calculation of ATC, transmission capacity 
necessary to accommodate native load growth reasonably forecasted in 
its planning horizon.\76\ As noted above, Order No. 888 granted a 
rollover right to existing firm service customers,\77\ but allowed 
transmission providers to restrict that rollover right if the capacity 
was reasonably forecasted to be needed to serve native load customers, 
as long as that restriction was specified in the customer's service 
contract.\78\
---------------------------------------------------------------------------

    \75\ Order No. 888 at 31,745.
    \76\ Id. at 31,694.
    \77\ Id.; pro forma OATT section 2.2.
    \78\ Order No. 888-A at 30,198.
---------------------------------------------------------------------------

    63. Congress in section 1233 of EPAct 2005 added section 217 to the 
FPA, entitled ``Native Load Service Obligation,'' which addresses 
transmission rights held by load-serving entities. It allows load-
serving entities to use their own and contracted-for transmission 
capacity to the extent required to meet their service obligations, 
without being subject to charges of unlawful discrimination. Among 
other things, FPA section 217 states that it does not require the 
abrogation of any contract or service agreement for firm transmission 
service or rights in effect as of the date of enactment.\79\
---------------------------------------------------------------------------

    \79\ 16 U.S.C. 217(f).
---------------------------------------------------------------------------

    64. In the NOI, the Commission stated that it was not proposing to 
change the protection of native load embodied in Order No. 888.\80\ The 
Commission sought comment on whether the approach the Commission took 
in Order No. 888 is the same as that set forth in FPA section 217.
---------------------------------------------------------------------------

    \80\ NOI at P 9.
---------------------------------------------------------------------------

Comments
    65. Several commenters argue that the approach the Commission took 
in Order No. 888 is largely consistent with the treatment of native 
load preference in FPA section 217.\81\ They state that Order No. 888 
makes clear that native load has a priority right to a transmission 
providers' capacity and that transmission providers may reserve a 
portion of their capacity for native load growth.
---------------------------------------------------------------------------

    \81\ E.g., Memphis Light, Newmont Mining Reply Comments, 
Progress Energy, and TDU Systems.
---------------------------------------------------------------------------

    66. Other commenters perceive varying degrees of difference between 
Order No. 888 and FPA section 217.\82\ EEI states that FPA section 217 
extends native load protection to all load-serving entities that have 
direct or indirect service obligations to end-users for terms of one 
year or more, while Order No. 888 does not. Nevada Companies and TAPS 
argue that the FPA section 217 requirement that the Commission exercise 
its authority to facilitate the planning and expansion of transmission 
facilities to satisfy the service obligations of load-serving entities 
necessitates changes to Order No. 888.
---------------------------------------------------------------------------

    \82\ E.g., Duke, EEI, Metropolitan Water District, and Southern.
---------------------------------------------------------------------------

    67. Several commenters argue that FPA section 217 requires the 
Commission to revisit its rollover rights policy.\83\ Duke maintains 
that the current Commission approach is not the same as set forth in 
either Order No. 888 or FPA section 217 because the Commission's 
current approach to rollover rights does not meaningfully recognize the 
native load preference. Commission decisions since Order No. 888, 
according to Duke, have weakened the native load preference envisioned 
in Order No. 888 to the point where the Commission's treatment of the 
native load preference is not what Congress provides in FPA section 
217. LPPC argues that FPA section 217 reverses Commission precedent 
that makes it impossible to recall capacity for native load once it is 
subject to a rollover right.
---------------------------------------------------------------------------

    \83\ E.g., Duke, Energy, LPPC, Progress Energy, Salt River, 
Santee Cooper, and Southern.
---------------------------------------------------------------------------

    68. EEI states that in order to harmonize Order No. 888 rollover 
rights with the native load protections contained in FPA section 217, 
the Commission should revise the pro forma OATT to require a notice 
period for rollover rights that is consistent with the time needed to 
plan for and construct transmission facilities to serve native load 
customers and the rollover customer. EEI and Salt River argue that FPA 
section 217 requires that the Commission permit load-serving entities 
to implement curtailment procedures that recognize native load service 
priorities.
    69. Metropolitan Water District argues that the mandate to preserve 
native load preference is complicated further when a transmission owner 
has transferred operational control to an ISO or RTO. In such a 
scenario, to honor the native load preference in FPA section 217, 
Metropolitan Water District contends that the Commission either should 
reconsider its prior rulings rejecting the allocation of physical 
rights to serve native load or should require ISOs and RTOs to issue 
financial rights options, in addition to financial right obligations, 
so that load-serving entities have a greater ability to avoid 
congestion costs in serving their native load.
Discussion
    70. The Commission concludes that the protection of native load 
embodied in Order No. 888 is consistent with FPA section 217, and we 
reaffirm our commitment to the protection of native load. Order No. 888 
gave public utilities the right to reserve existing transmission 
capacity needed for native load growth reasonably forecasted within the 
utility's current planning horizon. It also allowed transmission 
providers to restrict rollover rights based on a reasonably forecasted 
need at the time the contract is executed. This approach is consistent 
with FPA section 217, which protects the transmission rights of 
entities with service obligations to end-users or a distribution 
utility, to the extent required to meet their service obligations. 
Though commenters appear to believe FPA section 217 would support the 
cancellation of contracts that include rollover rights, FPA section 217 
by its terms does not contemplate abrogation of existing transmission 
service contracts.\84\ However, to the extent commenters argue that the 
terms of service and notice periods associated with the OATT rollover 
rights are too short to protect native load adequately, we note that we 
are proposing to extend them in this NOPR.
---------------------------------------------------------------------------

    \84\ See FPA section 217(f) (explaining that section 217 does 
not abrogate any firm service agreements or rights in effect as of 
the date of enactment).
---------------------------------------------------------------------------

    71. In response to Metropolitan Water District, the Commission 
finds that the issue of firm transmission rights in organized markets 
is best addressed as part of the long-term firm transmission rights 
rulemaking in Docket Nos. RM06-8-000 and AD05-7-000. We further note, 
in response to the comments of Nevada Companies and TAPS, that we are 
proposing a coordinated and regional planning process to facilitate the 
planning and expansion of transmission facilities pursuant to FPA 
section 217.
3. The Types of Transmission Services Offered
    72. In Order No. 888, the Commission required all public utilities 
to offer on a non-discriminatory, open-access basis firm network 
service and firm and non-

[[Page 32648]]

firm point-to-point service. In the NOI, the Commission sought comments 
on whether the Commission should require transmission providers to 
offer transmission services in addition to, or in place of, the point-
to-point and network services prescribed in the OATT.
    73. Among other questions, the Commission asked whether network 
service alone or both network and point-to-point services should be 
converted into a single contract demand service.\85\ Generally 
speaking, contract demand service is a hybrid of point-to-point and 
network services that is reservation-based and allows transmission 
customers to receive a firm entitlement to integrate multiple resources 
and deliver energy to multiple points, without paying a separate charge 
for each point of receipt or delivery. Contract demand service would 
allow current point-to-point customers to avoid having to arrange and 
pay for separate reservations for each point of receipt. And current 
network customers would be allowed to pay for transmission based on the 
amount of their reservation rather than customer loads at a delivery 
point.
---------------------------------------------------------------------------

    \85\ For examples of contract demand service, the Commission 
cited Florida Power Corp., FERC ] 61,248 (1995); Wisconsin Electric 
Power Co., 72 FERC ] 61,033 (1995); and Florida Power Corp., 81 FERC 
] 61,247 (1997).
---------------------------------------------------------------------------

Comments
    74. Most commenters argue against requiring that network service 
alone or in combination with point-to-point service be converted into 
contract demand service.\86\ Some warn that the imposition of this 
service would interfere with efficient transmission system planning and 
operation due to increased capacity reservations that would go 
unused.\87\ They also argue that it would result in significant cost 
shifts among transmission customers if not priced correctly. FP&L 
argues that the current services are a better match for the actual use 
of the transmission system and thereby permit more ATC to be available.
---------------------------------------------------------------------------

    \86\ E.g., Ameren, APPA, Bonneville, Calpine, EEI, EPSA, Fallon 
Reply Comments, FP&L, NRECA, PacifiCorp, Southern, Suez Energy NA, 
TVA, TAPS, and TDU Systems.
    \87\ E.g., EEI, FP&L, KCP&L, and TVA.
---------------------------------------------------------------------------

    75. Some commenters ask that the Commission require transmission 
providers to offer contract demand service as an additional 
transmission service option in the pro forma OATT.\88\ AMP-Ohio argues 
that, as long as Commission policy requires network customers to pay 
load-ratio network transmission charges for load served with behind-
the-meter generation, contract demand network service is essential to 
avoid unduly discriminatory transmission charges. Midwest Municipals 
and FMPA argue that the Commission should order contract demand service 
where the transmission provider does not plan and operate its system to 
meet total customer load because, as the Commission stated in Order No. 
888, full network service is essential for achieving comparability and 
efficient integration of power supply and load. FMPA contends that 
where a customer needs network service from another system for only 
part of its load, it would benefit from being able to buy system power 
from multiple designated resources for part of its load. In this way, 
FMPA continues, the transmission provider would not have the planning 
obligation for the customer's entire load, perhaps avoiding or delaying 
expensive transmission additions. FMPA claims that such service would 
tend to benefit all transmission users because it would allow a more 
efficient use of the grid and provide additional transmission revenues.
---------------------------------------------------------------------------

    \88\ E.g., AMP-Ohio, APPA, Cogeneration Association of 
California Reply Comments, Constellation, EPSA, FMPA Reply Comments, 
Midwest Municipals, PacifiCorp, and Public Power Council.
---------------------------------------------------------------------------

    76. Other commenters state that transmission providers should have 
the option whether to offer contract demand or other customized 
transmission services.\89\ LPPC argues that the Commission should allow 
a transmission provider to voluntarily provide alternative forms of 
transmission service where circumstances support their implementation, 
with the caveat that such service must not place any market participant 
at a disadvantage or increase transmission rates for network or point-
to-point customers. Southern proposes that the pro forma OATT be 
modified to include a process through which a transmission provider may 
propose to adopt new services that customers specifically request.
---------------------------------------------------------------------------

    \89\ E.g., LPPC, NRECA, and Southern.
---------------------------------------------------------------------------

    77. Commenters also raise general concerns regarding the use and 
potential abuse of network contract demand service. For example, 
MidAmerican argues that contract demand service should not be used as a 
means for transmission customers with behind-the-meter generation to 
avoid paying for a load-ratio share of a system that was built to 
support their entire load and on which they rely for service. Rather, 
MidAmerican continues, network contract demand service should be 
limited to situations in which deliverability is physically limited, 
such as where the integrated transmission system does not have the 
capacity to serve all the load at a designated point of delivery. EEI 
argues that the Commission should not convert network service to 
network contract demand service because conversion would result in a 
substantial reduction in ATC as it would provide contract rights on the 
transmission system on an around-the-clock basis that are equal to 
network load's monthly or annual peak loads.
Discussion
    78. We propose to retain the services we ordered in Order No. 888: 
firm and non-firm point-to-point service and firm network service. We 
do not propose requiring transmission providers to adopt a network 
contract demand service, either as a replacement for network or point-
to-point service or as a third category of service under the OATT. The 
Commission continues to believe that network and point-to-point 
services are the appropriate base-line service offerings in the OATT. 
Although forms of contract demand service have been approved by the 
Commission, and the service may provide benefits to certain customers, 
sufficient potential drawbacks exist that prevent us from concluding 
that it is a necessary transmission service that should be included in 
the pro forma OATT. For example, the service would require a departure 
from full load-ratio pricing for network customers, which may not be 
warranted to the extent the transmission provider plans its system to 
serve all native load. While the Commission concludes that it will not 
require all transmission providers to offer this service, we 
acknowledge that the introduction of this service on a voluntary basis 
may be appropriate in certain circumstances.
    79. Although we are not proposing to require that transmission 
providers adopt contract demand service, we note that the commenters 
who support this service appear concerned principally with inequities 
in the pricing of network integration service. The Commission is 
addressing certain of these concerns elsewhere in the NOPR. For 
example, in this NOPR, we propose to modify our treatment of 
transmission credits for new transmission facilities and clarify that 
the transmission provider must satisfy the comparability requirement 
when including transmission facilities in its rate base for pro forma 
OATT purposes. We also address concerns regarding the linkage between 
how the transmission provider plans and

[[Page 32649]]

operates its system through proposed revisions to planning and ATC.
4. Functional Unbundling
    80. When the Commission proposed the open access policy that 
culminated in Order No. 888, there was considerable debate about 
whether corporate unbundling (in which a public utility's transmission 
and generation assets would be placed in separate corporate entities) 
was necessary to ensure non-discriminatory open access transmission 
service. The Commission decided to mandate functional, rather than 
corporate, unbundling of transmission and generation services. In Order 
No. 888, the Commission explained that functional unbundling has three 
components:

    1. A public utility must take transmission services (including 
ancillary services) for all of its new wholesale sales and purchases 
of energy under the same tariff of general applicability as do 
others;
    2. A public utility must state separate rates for wholesale 
generation, transmission, and ancillary services;
    3. A public utility must rely on the same electronic information 
network that its transmission customers rely on to obtain 
information about its transmission system when buying or selling 
power.\90\
---------------------------------------------------------------------------

    \90\ Order No. 888 at 31,654.

    81. In the years following Order No. 888, a number of public 
utilities nonetheless underwent corporate unbundling. Many of these 
entities did so as a result of state-mandated restructuring laws. 
Others did so for corporate or tax reasons. Some entities divested all 
of their generation assets to a non-affiliate, while others simply 
restructured internally to place the generation assets in a different 
corporate subsidiary than the transmission assets. There remain, 
however, a significant number of vertically-integrated public utilities 
that have operated under the functional unbundling approach.
Comments
    82. Retention of Order No. 888's functional unbundling approach is 
supported by a number of commenters. For example, the LPPC states that 
vertical integration remains a viable business model for serving 
customers reliably and at economic rates. LG&E posits that, absent a 
proven and real level of abuse, major structural changes are 
unwarranted. NARUC argues that the issue of whether there should be 
structural separation of generation from transmission is best left to 
the states. NPPD alleges that mandatory vertical unbundling would do 
more harm than good by threatening the continued economic operation of 
those utilities that continue to provide bundled service to their 
retail native load customers. The North Carolina Commission does not 
believe the evidence in that state supports the imposition of 
structural remedies.
    83. Some commenters, however, continue to urge the Commission to 
impose structural separation. National Grid contends that the best way 
to eliminate the possibility of undue discrimination is to separate the 
ownership and operation of the transmission system from interests in 
the market. Calpine urges the Commission to structurally separate the 
merchant function that is engaged in selling power for resale from 
those who control access to transfer capability and service, not just 
those who operate the transmission system. TAPS argues that structural 
solutions are preferable to behavioral rules.
    84. Many commenters favoring structural separation urge the 
Commission to impose an independent transmission coordinator 
requirement. These commenters would have transmission providers employ 
an independent entity to administer their OATTs, performing such 
functions as maintaining the utility's OASIS, granting or denying 
service requests, reviewing system impact and facilities study results, 
and overseeing decisions with respect to line ratings, transmission 
outages and generation dispatch.\91\ Other commenters oppose the 
imposition of a potentially costly new layer of bureaucracy, at least 
on a generic basis.\92\
---------------------------------------------------------------------------

    \91\ E.g., Arkansas Commission, Calpine, Constellation, EPSA, 
and PPL.
    \92\ E.g., APPA, NRECA, and TAPS.
---------------------------------------------------------------------------

Discussion
    85. We propose to preserve the functional unbundling approach 
adopted by Order No. 888. For public utilities that kept transmission 
and generation assets in the same corporate entity, the Commission 
imposed strict Standards of Conduct that required separation of the 
utilities' transmission system operations and wholesale marketing 
functions.\93\ These Standards of Conduct were replaced by a broader 
set of rules adopted in Order No. 2004.\94\ These rules require that 
employees engaged in transmission functions operate separately from 
employees of energy affiliates and marketing affiliates. A number of 
information sharing restrictions also apply, which prohibit 
transmission providers from allowing employees of their energy and 
marketing affiliates to obtain access to transmission or customer 
information, except via OASIS.
---------------------------------------------------------------------------

    \93\ Order No. 889 at 31,595.
    \94\ See Standards of Conduct for Transmission Providers, Order 
No. 2004, 68 FR 69134 (Dec. 11, 2003), FERC Stats. & Regs. ] 31,155 
(2003), order on reh'g, Order No. 2004-A, 69 FR 23562 (Apr. 29, 
2004), FERC Stats. & Regs. ] 31,161 (2004), order on reh'g, Order 
No. 2004-B, 69 FR 28371 (Aug. 10, 2004), FERC Stats. & Regs. ]31,166 
(2004), order on reh'g, Order No. 2004-C, 70 FR 284 (Jan. 4, 2005), 
FERC Stats. & Regs. ] 31,172 (2005), order on reh'g, Order No. 2004-
D, 110 FERC ] 61,320 (2005), appeal docketed sub nom. National Gas 
Fuel Supply Corporation v. FERC, No. 04-1183 (D.C. Cir. June 9, 
2004), codified at 18 CFR Part 358 (2005).
---------------------------------------------------------------------------

    86. The Commission aggressively enforces the Standards of Conduct. 
The Commission's Office of Enforcement is well-suited to investigate 
potential violations of the Standards of Conduct and to propose 
remedies, including structural remedies if necessary, to ensure that 
the separation of function and information restrictions in Order No. 
2004 are implemented.
    87. The Commission has resolved a number of complaints related to 
the Standards of Conduct and the accompanying OASIS posting 
requirements.\95\ In Order No. 888, the Commission noted that the 
possibility of filing a complaint under FPA section 206 is an 
additional safeguard if a public utility seeks to circumvent the 
functional unbundling requirement. The Commission's Enforcement Hotline 
likewise is available to customers that do not wish to file a formal 
complaint.
---------------------------------------------------------------------------

    \95\ See Aquila Energy Marketing Corp. v. Niagara Mohawk Power 
Corp., 87 FERC ] 61,328 (1999)(finding that off-OASIS communicagtion 
between utilty and its marketing affiliate led to preferential 
treatment of the affiliate).
---------------------------------------------------------------------------

    88. In addition, one of the criticisms of the functional unbundling 
requirement is that Order No. 888 leaves vertically integrated 
utilities with too much discretion in applying the OATT and gives them 
an incentive to use this discretion to their advantage. We agree that 
the existing pro forma OATT provides too much discretion in certain 
important areas. It is for this reason--as explained elsewhere in the 
NOPR--that we are proposing to require greater clarity and transparency 
in several areas of OATT administration. We believe these reforms will 
limit the discretion of transmission providers and make any remaining 
attempts to discriminate much easier to detect.
    89. We believe that this increased clarity and transparency, when 
coupled with the Standards of Conduct and a rigorous enforcement 
program, will ensure that the functional unbundling requirement will 
serve its original purpose. As a result, just as the Commission 
concluded in Order No.

[[Page 32650]]

888 that more intrusive and costly corporate unbundling was not 
necessary, the Commission again concludes that there is no need to 
impose a corporate or structural unbundling requirement at this time. 
We believe that the pro forma OATT, if properly clarified and enforced, 
will enable us to eliminate the opportunity for undue discrimination in 
the provision of transmission service.
    90. For the same reasons, we also decline to mandate an independent 
transmission coordinator for all transmission providers. We have 
concluded that such entities may be appropriate in certain 
circumstances and we support voluntary efforts to rely on them.\96\ We 
do not agree, however, that there is sufficient basis for requiring 
them as a generic remedy for undue discrimination.
---------------------------------------------------------------------------

    \96\ See Duke Power, 113 FERC ] 61,288 (2005); MidAmerican 
Energy Co., 113 FERC ] 61,274 (2005); see also Entergy Services, 
Inc., 110 FERC ] 61,295 (2005), order clarificaiton, 111 FERC ] 
61,222 (2005), order conditionally approving filing, 115 FERC ] 
61,095 (2006).
---------------------------------------------------------------------------

    91. Our proposal to retain the functional unbundling approach of 
Order No. 888 does not suggest, however, a lack of support for 
structural changes that may be undertaken on a voluntary basis by each 
region, such as transmission-only companies, RTOs, or other reforms. We 
continue to support such efforts as potentially providing significant 
benefits in several areas, including, but not limited to, increased 
infrastructure investment and addressing regional issues such as cost 
recovery, pancaked rates, loop flow, and congestion management. At this 
time, we believe such efforts are best developed on a voluntary basis.

C. Applicability of the Proposed Rule

1. Public Utility Transmission Providers
    92. Pursuant to its authority under FPA sections 205 and 206, the 
Commission in Order No. 888 required all public utilities that owned, 
controlled, or operated facilities used for transmitting electric 
energy in interstate commerce to file open access transmission tariffs 
that contained minimum terms and conditions of non-discriminatory 
service. The Commission recognized, however, that there may be 
circumstances in which a public utility believes that the pro forma 
OATT does not provide sufficient flexibility.\97\ In addition, the 
Commission acknowledged that a public utility might be willing to offer 
superior non-rate terms and conditions. As a result, the Commission 
allowed a transmission provider to justify variations from the non-
price terms and conditions of the pro forma OATT under two 
circumstances. First, certain provisions of Order No. 888 specifically 
allowed public utilities to use alternatives that were justified by 
``regional differences.'' When submitting those provisions, public 
utilities were permitted to follow regional practices when doing so was 
``reasonable, generally accepted in the region, and consistently 
adhered to by the transmission provider,''\98\ as long as the utilities 
identified the regional practices in their compliance filings. Second, 
in subsequent FPA section 205 proceedings, public utilities were 
permitted to propose changes to any pro forma OATT provision that were 
``consistent with or superior to'' the terms of the pro forma OATT.
---------------------------------------------------------------------------

    \97\ Order No. 888 at 31,770.
    \98\ Id.
---------------------------------------------------------------------------

    93. In the NOI, the Commission expressed the preliminary view that 
reforms to the pro forma OATT and public utilities' OATTs appear 
necessary and sought comment on how best to accomplish that. In 
particular, the Commission sought comment on whether reforms to Order 
No. 888 should be applied to all public utility transmission providers, 
including those that are approved ISOs, RTOs, or independent 
transmission coordinators.
Comments
    94. Independent system operators such as MISO, CAISO, and ISO New 
England submit that many of the concerns raised by the Commission in 
the NOI already have successfully been addressed by the operation of 
ISOs and RTOs. Similarly, EEI argues that many of the issues addressed 
in the NOI are not applicable to RTOs and ISOs because RTOs and ISOs 
are independent of all market participants and therefore are presumed 
to not engage in undue discrimination or preferential treatment. PJM 
argues that, because of its independence, the transparency of its 
procedures, and the progress achieved in developing effective financial 
and non-financial congestion management tools, PJM structurally 
addresses the continuing concerns of the Commission regarding 
persistent undue discrimination and preference in the industry.
    95. EPSA states that it may not be necessary to apply all aspects 
of the new OATT to ISOs or RTOs. However, rather than delineating 
either each term that would not apply to an RTO or how such terms might 
be modified in an RTO tariff, EPSA recommends that the Commission 
require RTOs, ISOs, and independent transmission coordinators to submit 
compliance filings upon issuance of the new pro forma OATT but allow 
them to propose waivers of the new requirements based upon appropriate 
justification.
    96. EEI argues that, to the extent that the Commission requires 
RTOs and ISOs to amend their open access transmission tariffs, the 
Commission should establish flexible procedures that provide the RTOs 
and ISOs the right to customize their OATTs consistent with their 
independent status.
    97. Other commenters argue that reforms to existing OATTs should be 
applied to all market entities, including ISOs, RTOs and independent 
transmission coordinators.\99\ LPPC states that there is little reason 
for the Commission to be more deferential in considering deviations 
from the pro forma OATT proposed by RTOs or ISOs than it is with 
respect to investor-owned utilities.
---------------------------------------------------------------------------

    \99\E.g., Calpine, LPPC, NRECA, and Santa Clara.
---------------------------------------------------------------------------

Discussion
    98. The Commission proposes to apply the final rule to all public 
utility transmission providers. The Commission proposes to require all 
such transmission providers to submit FPA section 206 compliance 
filings, within 60 days following publication of the final rule in the 
Federal Register, that contain the non-rate terms and conditions set 
forth in the final rule. We note that certain non-rate terms and 
conditions, such as Attachment C relating to the transmission 
provider's ATC calculation methodology and Attachment K relating to the 
transmission provider's transmission planning process, may require more 
than 60 days to prepare. We seek comment on an appropriate time period 
in which to require the submission of these attachments.
    99. As we did in Order No. 888, after making their FPA section 206 
compliance filings, we propose to allow transmission providers to 
submit filings under FPA section 205 proposing rates for the services 
provided for in the tariff as well as non-rate terms and conditions 
that differ from those set forth in the final rule if those provisions 
are ``consistent with or superior to'' the pro forma OATT.
    100. With respect to an RTO or ISO, we recognize that such an 
entity may already have tariff terms and conditions that are superior 
to the pro forma OATT. Thus, we propose to require RTO and ISO 
transmission providers to submit FPA section 206 compliance filings, 
within 90 days following publication of the final rule in the

[[Page 32651]]

Federal Register, that contain the non-rate terms and conditions set 
forth in the final rule or that demonstrate that their existing tariff 
provisions are consistent with or superior to the revised provisions to 
the pro forma OATT. Similarly, after making their FPA section 206 
compliance filings, we propose to allow RTOs and ISOs to submit filings 
under FPA section 205 proposing rates for the services provided for in 
their tariffs as well as non-rate terms and conditions that differ from 
their existing tariffs and those set forth in the final rule if those 
provisions are ``consistent with or superior to'' the pro forma OATT.
    101. We generally note that the purpose of this NOPR is not to 
redesign approved, fully-functional RTO or ISO markets. We do not 
expect that substantial changes to those markets would be required as a 
result of this NOPR. For example, some RTOs or ISOs have eliminated 
point-to-point service for internal transactions in favor of a form of 
more flexible network service. Thus, we would not expect our reforms to 
ATC to require changes to the way in which such RTOs or ISOs assess 
whether capacity for traditional network or point-to-point service is 
available within their footprints. However, there may be elements of 
the proposed reforms that are superior to what currently exists in some 
RTOs or ISOs, e.g., transparency, data exchange or planning, which 
would require the RTO or ISO to conform to the pro forma OATT.
2. Non-Public Utility Transmission Providers/Reciprocity
    102. In Order No. 888, the Commission conditioned non-public 
utilities' use of public utility open access services on an agreement 
to offer comparable transmission services in return.\100\ The 
Commission found that while it did not have the authority to require 
non-public utilities to make their systems generally available, it did 
have the ability and the obligation to ensure that open access 
transmission is as widely available as possible and that Order No. 888 
did not result in a competitive disadvantage to public utilities.
---------------------------------------------------------------------------

    \100\ These entities are not FPA public utilities and therefore 
are not subject to the Commission's jurisdiction under sections 205 
and 206 of the FPA.
---------------------------------------------------------------------------

    103. Under the reciprocity provision in section 6 of the pro forma 
OATT, if a public utility seeks transmission service from a non-public 
utility to which it provides open access transmission service, the non-
public utility that owns, controls, or operates transmission facilities 
must provide comparable transmission service that it is capable of 
providing on its own system. Under the OATT, a public utility may 
refuse to provide open access transmission service to a non-public 
utility if the non-public utility refuses to reciprocate. A non-public 
utility may satisfy the reciprocity condition in one of three ways: 
first, it may provide service under a tariff that has been approved by 
the Commission under the voluntary ``safe harbor'' provision. A non-
public utility using this alternative submits a reciprocity tariff to 
the Commission seeking a declaratory order that the proposed 
reciprocity tariff substantially conforms to, or is superior to, the 
pro forma OATT. The non-public utility then must offer service under 
its reciprocity tariff to any public utility whose transmission service 
the non-public utility seeks to use. Second, the non-public utility may 
provide service to a public utility under a bilateral agreement that 
satisfies its reciprocity obligation. Finally, the non-public utility 
may seek a waiver of the reciprocity condition from the public 
utility.\101\
---------------------------------------------------------------------------

    \101\ See Order No. 888-A at 30,285-86.
---------------------------------------------------------------------------

    104. In EPAct 2005, Congress authorized, but did not require, the 
Commission to order non-public utilities (or ``unregulated transmitting 
utilities'') to provide transmission services. Section 1231 of EPAct 
2005 establishes a new section 211A in Part II of the FPA, which states 
in part that the Commission ``may, by rule or order, require an 
unregulated transmitting utility to provide transmission services'' at 
rates that are comparable to those it charges itself and under terms 
and conditions (unrelated to rates) that are comparable to those it 
applies to itself and that are not unduly discriminatory or 
preferential. The language does not limit the Commission to ordering 
transmission services only to the public utility from whom the non-
public utility takes transmission services, but rather it can 
reasonably be read to permit the Commission to order the non-public 
utility to provide ``open access'' transmission service, i.e., service 
to all eligible customers.
    105. In the NOI, we sought comment on whether the Commission should 
exercise the authority granted to it by Congress in FPA section 211A. 
If so, we asked whether the Commission should impose this requirement 
on all unregulated transmitting utilities through a rulemaking 
proceeding, or whether the Commission should instead apply this new law 
on a case-by-case basis, through complaints, motions seeking 
enforcement, or sua sponte action by the Commission.
Comments
    106. Several non-public utility commenters suggest that the 
Commission should not use the authority granted by FPA section 211A in 
a generic fashion.\102\ They argue that there is no need to require 
unregulated transmitting utilities either to file open access tariffs 
with the Commission or to require that they adhere to a pro forma OATT. 
APPA asserts that while the Commission may act under FPA section 211A 
to remedy particular issues that are brought to its attention with 
respect to lack of access, there is simply no basis for concluding that 
there currently exists a general problem regarding the provision of 
transmission service by non-public utility transmission providers which 
calls for a generic solution. LPPC proposes a regime of voluntary 
compliance with a set of proposed comparability guidelines.
---------------------------------------------------------------------------

    \102\ E.g., Chelan, Douglas, LDWP, LPPC, Northwest Unregulated 
TUs, Public Power Council, Rural Utilities Service, Sacramento, 
Santee Cooper, Snohomish, Tacoma, TAPS, and TVA.
---------------------------------------------------------------------------

    107. Many commenters argue that the Commission should exercise its 
authority granted by FPA section 211A by establishing a rule to require 
unregulated transmitting utilities to provide service under the pro 
forma OATT.\103\ EEI believes a rulemaking is essential to ensure that 
all utilities required to provide open access under FPA section 211A do 
so and that the Commission should, at a minimum, require unregulated 
transmitting utilities to file and provide service under the pro forma 
OATT. EPSA and Sempra Global suggest an approach that would not require 
an unregulated transmitting utility to file an OATT with the Commission 
until it receives a request for service.
---------------------------------------------------------------------------

    \103\ E.g., Ameren, California Commission, Calpine, Cinergy, 
EEI, First Energy, Memphis Light, Nevada Companies, Northwest IPPs, 
PNM-TNMP, PPL, Progress Energy, and Suez Energy NA.
---------------------------------------------------------------------------

    108. EEI argues that the Commission should use FPA section 211A to 
require unregulated transmitting utilities to provide all services they 
are capable of providing, not just those that they provide to 
themselves. In contrast, APPA states that FPA section 211A establishes 
a ``comparability'' standard applicable to non-public utility 
transmission owner rates, and a ``comparable and not unduly 
discriminatory or preferential'' standard for terms and conditions. 
APPA further states that FPA section 211A requires that unregulated 
transmitting utilities provide transmission service to others at

[[Page 32652]]

rates, terms and conditions ``comparable to those under which the 
unregulated transmitting utility provides transmission services to 
itself,'' rather than transmission services that they are ``reasonably 
capable of providing.''
    109. The Canadian Electricity Association believes that the 
adoption of FPA section 211A requires the Commission to revisit the 
reciprocity requirement of Order No. 888. According to the Canadian 
Electricity Association, EPAct 2005 lowered the bar for domestic 
unregulated transmitting utilities, requiring them only to provide 
service under terms and conditions that are comparable to those they 
apply to themselves, rather than terms and conditions that 
substantially conform or are superior to those in the pro forma OATT. 
If the Commission does not make corresponding changes to the manner in 
which the reciprocity requirement currently applies to Canadian 
entities, it argues, the result will be domestic unregulated 
transmitting utilities being treated better than Canadian entities, 
which would violate the national treatment obligations under the North 
American Free Trade Agreement. The Canadian Electricity Association 
argues that the reciprocity requirement under Order No. 888 must be 
modified to require that a Canadian entity that seeks open access in 
the U.S. must provide access to its own transmission system under terms 
and conditions that are comparable to those the Canadian entity is 
subject to itself.
Discussion
    110. The Commission proposes to retain the current reciprocity 
language in the pro forma OATT, as well as Order No. 888's three 
alternative provisions for satisfying the reciprocity condition, which 
are described above: a non-public utility that owns, controls, or 
operates transmission and seeks transmission service from a public 
utility must either satisfy its reciprocity obligation under a 
bilateral agreement, seek a waiver of the OATT reciprocity condition 
from the public utility, or file a safe harbor tariff with the 
Commission.\104\
---------------------------------------------------------------------------

    \104\ For non-public utilities that choose to use the safe 
harbor tariff, we note that its provisions must be substantially 
conforming or superior to the new pro forma OATT. A non-public 
utility that already has a safe harbor tariff may amend its tariff 
so that its provisions substantially conform or are superior to the 
new pro forma OATT if it wishes to continue to qualify for safe 
harbor treatment. As the Commission stated in Order No. 888-A, a 
non-public utility may limit the use of its voluntarily offered safe 
harbor reciprocity tariff only to those transmission providers from 
whom the non-public utility obtains open access service, as long as 
the tariff otherwise substantially conforms to the pro forma OATT. 
See Order No. 888-A at 30,289.
---------------------------------------------------------------------------

    111. We do not propose a generic rule to implement the new FPA 
section 211A.\105\ Rather, we will apply its provisions on a case-by-
case basis, such as when a public utility seeks service from an 
unregulated transmitting utility that has not requested service under 
the public utility's OATT and the reciprocity obligation therefore does 
not apply.\106\ A customer may file an application with the Commission 
seeking an order compelling the unregulated transmitting utility to 
provide transmission service that meets the standards of FPA section 
211A. Further, as we indicate below, we expect unregulated transmission 
providers to participate in the open and transparent regional planning 
processes that we propose to order and note that, if there are 
complaints about such participation, we will address them on a case-by-
case basis.
---------------------------------------------------------------------------

    \105\ We note that LPPC has committed to voluntary compliance 
with a set of guidelines for the provision of comparable service 
under FPA section 211A.
    \106\ We do, however, propose to amend our regulations to make 
clear that an applicant in a FPA section 211A proceeding against a 
non-public utility that has submitted an acceptable safe harbor 
tariff shall have the burden of proof to show why service under the 
safe harbor tariff is not sufficient and why a FPA section 211A 
order should be granted. See revised 18 CFR 35.28(e)(1)(ii).
---------------------------------------------------------------------------

    112. We disagree with the position of the Canadian Electricity 
Association. EPAct 2005 did not repeal the reciprocity obligation in 
Order No. 888. Rather, it granted a new avenue of authority to the 
Commission to order comparable transmission service from non-public 
utilities. We are proposing not to exercise this new authority at this 
time. Rather, we are proposing to retain our reciprocity policy, which 
was adopted pursuant to sections 205 and 206 of the FPA. By maintaining 
the same reciprocity requirement for domestic, non-public utilities as 
for foreign utilities doing business in the United States, the 
Commission will ensure that foreign entities will continue to be 
treated no less favorably than domestic, non-public utilities.

V. Proposed Modifications of the OATT

A. Consistency and Transparency of ATC Calculations

    113. In Order Nos. 888 and 889, the Commission directed 
transmission providers to offer their unused transfer capability to the 
market and to post the amount of ATC \107\ on OASIS. At the time those 
orders were issued, the Commission noted that formal methods did not 
exist for calculating ATC, but recognized that there were industry 
efforts underway to develop a consistent, industry-wide method for 
calculating it.\108\ Instead of prescribing a specific methodology for 
calculating ATC in Order Nos. 888 and 889, the Commission encouraged 
the industry efforts and required that transmission providers base 
their ATC calculation methodologies on current industry practices, 
standards and criteria.\109\ In addition, the Commission directed 
transmission providers to include a description of their ATC 
calculation methodologies in Attachment C of their tariffs.
---------------------------------------------------------------------------

    \107\ See supra note 7.
    \108\ Order No. 889 at 31,607.
    \109\ Id.
---------------------------------------------------------------------------

    114. Ten years later, however, although some progress has been 
made, the industry still has not developed a consistent, industry-wide 
methodology for evaluating ATC. In the intervening years, the industry, 
working through the North American Electric Reliability Council (NERC), 
has adopted a general definition of ATC, which establishes a basic 
methodology for evaluating ATC. NERC also has developed a set of 
guiding principles for calculating ATC and has encouraged further 
consistency of ATC calculation methodologies on a regional level. NERC 
defines ATC as the transfer capability remaining on the system for 
further commercial activity over and above already committed uses. This 
value is determined by deducting existing transmission commitments 
(ETC) \110\ (including transmission reservations, network and retail 
customer service), capacity benefit margin (CBM),\111\ and transmission 
reliability margin (TRM) \112\ from total

[[Page 32653]]

transfer capability (TTC).\113\ However, NERC's calculation methodology 
is not prescriptive; it establishes a framework for evaluating ATC, 
which leaves open to each transmission provider's interpretation and 
discretion the specific algorithm, data inputs and assumptions needed 
to assess ATC.\114\ Consequently, transmission providers have developed 
numerous ways to evaluate ATC using their own algorithms, data and 
modeling assumptions.\115\
---------------------------------------------------------------------------

    \110\ NERC does not have a formal definition or standard 
methodology for ETC.
    \111\ NERC defines CBM as the amount of firm transmission 
transfer capability preserved by the transmission provider for load-
serving entities, whose loads are located on that transmission 
service provider's system, to enable access by the load-serving 
entities to generation from interconnected systems to meet 
generation reliability requirements. Preservation of CBM for a load-
serving entity allows that entity to reduce its installed generating 
capacity below that which may otherwise have been necessary without 
interconnections to meet its generation reliability requirements. 
The transmission transfer capability preserved as CBM is intended to 
be used by the load-serving entities only in times of emergency 
generation deficiencies. See North American Electric Reliability 
Council, Glossary of Terms Used in Reliability Standards, (Effective 
April 1, 2005), (NERC Glossary) available at ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Glossary_07Feb06.pdf
.

    \112\ NERC defines TRM as the amount of transmission transfer 
capability necessary to provide reasonable assurance that the 
interconnected transmission network will be secure. TRM accounts for 
the inherent uncertainty in system conditions and the need for 
operating flexibility to ensure reliable system operation as system 
conditions change. See NERC Glossary.
    \113\ NERC defines TTC as the amount of electric power that can 
be moved or transferred reliably from one area to another area of 
the interconnected transmission systems by way of all transmission 
lines (or paths) between those areas under specified system 
conditions. See NERC Glossary.
    \114\ See NERC, Available Transfer Capability Definitions and 
Determination: A Framework for Determining Available Transfer 
Capabilities of the Interconnected Transmission Networks for a 
Commercially Viable Electricity Market (1996) available at ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/atcfinal.pdf
.

    \115\ See supra note 59.
---------------------------------------------------------------------------

    115. Although transmission providers across the Nation have 
developed various methodologies, in general, there are two main 
approaches to calculating ATC used in the industry. The first is the 
contract path approach, which is more commonly used by transmission 
providers in the Western Electricity Coordinating Council (WECC) 
region.\116\ The contract path methodology derives ATC directly from 
predetermined TTC, ETC, CBM, and TRM values derived consistent with 
contract path transmission rights. The second method is the flowgate 
\117\ approach, which is used more widely in the Eastern 
Interconnection.\118\ The flowgate methodology is based on physical 
power flow models. The flowgate calculation first determines AFC and 
then converts AFC into ATC and derives TTC for the OASIS posting. The 
differences between the two approaches may not result in significantly 
different ATC values if consistent data inputs and industry acceptable 
modeling assumptions are used. Without a consistent and transparent 
approach to evaluating ATC, transmission customers will remain wary 
when service is denied and transmission providers will be the subject 
of suspicion and heightened scrutiny, especially given the increasingly 
congested state of the Nation's electric grid.
---------------------------------------------------------------------------

    \116\ See, e.g., Determination of Available Transfer Capability 
within the Western Interconnection (June 2001), available at http://www.wecc.biz/documents/library/procedures/ATC-apprdec01.pdf
.

    \117\ A flowgate is a designated point on the transmission 
system used in the modeling of power flows. While NERC currently 
does not have a formal definition for AFC, the power industry 
commonly defines AFC as a measure of the capability remaining on a 
flowgate for future uses, after considering the effect of prior 
sales. Mathematically, the industry measures AFC as AFC = Flowgate 
rating--[(base case flow)--(impacts of existing reservations)]--
FlowgateCBM--FlowgateTRM.
    \118\ See, e.g., PJM Manual 2: Transmission Service Request 
(April 14, 2005), available at: http://www.pjm.com/contributions/pjm-manuals/pdf/m02v08.pdf_____________________________________-

Consistency
    116. Generally, transmission providers calculate ATC by creating a 
base model of their system using a set of data inputs and assumptions, 
which are determined by the transmission provider. The transmission 
provider uses the model to perform various computer simulations of the 
operations of its system to determine the levels of transfer capability 
available on the system. The types of data and assumptions used in the 
models include, for example, facility ratings, the operating status of 
facilities, and generation dispatch, which might be supported by 
history, transmission plans, or the judgment of the transmission 
provider. For example, a transmission provider could use its judgment 
to reduce a facility rating or model certain facilities as out of 
service, which would have the effect of calculating a lower TTC value. 
A transmission provider also may use generation dispatch assumptions to 
limit transfer capability that otherwise would have been available to 
independent generators, thereby favoring the transmission provider's 
own generation. A transmission provider usually assumes that designated 
network resources are dispatched in economic merit order. However, a 
transmission provider has the discretion to decide which of the 
generators that are not designated network resources will be modeled 
in-service. Assumptions like these influence the loading on 
transmission lines in the model and heavily influence the resulting 
ATC. Having standards in place that address the calculation of ATC 
components, data inputs, and modeling assumptions would help ensure 
non-discriminatory treatment by limiting a transmission provider's 
ability to use discretion to the disadvantage of competitors and the 
market.
    117. As noted above, NERC does not have a formal definition of ETC. 
Without clear criteria for what should be included in a transmission 
provider's ETC, a transmission customer might not know whether ETC is 
being over- or underestimated. For example, a transmission provider 
could set aside more capacity for native load than is realistically 
expected to occur. This could happen if a transmission provider 
includes in ETC excess capacity for a load-serving entity (such as 
capacity to meet generation reserve requirements) but then also has a 
CBM component in its calculation of ATC that includes the same 
capacity. A transmission provider also could overestimate its ETC by 
double-counting the same transmission reservations in its ATC 
calculation. For example, this could happen if a transmission provider 
fails to replace a transmission reservation with the associated real-
time schedule, and as a result does not release non-firm ATC. A 
consistent process for calculating ETC will limit the subjectivity of 
the transmission provider's decisions and provide a more uniform method 
for estimating ETC.
    118. With respect to the modeling of a particular transaction, when 
information concerning the source is unknown, a transmission provider 
has the discretion to select which generator(s) will be used as a 
source.\119\ There are no standards for how that modeling should be 
done and, consequently, a transmission provider could model a source 
using single or multiple generators by increasing (scaling up) their 
output. In general, modeling a transaction using multiple generators as 
a source is less conservative for the transmission system than modeling 
a transaction using a single generator as a source. Modeling a 
transaction using multiple generators as a source typically results in 
a higher ATC value. Conversely, when a transmission provider models a 
transaction using a single generator as a source, this can result in a 
lower ATC value depending on the location of the generator. Modeling of 
contingency outages used for calculating ATC is another area within the 
discretion of the transmission provider. Although the type of 
contingency, such as single contingency (n-1), is determined by 
governing reliability criteria,\120\ the transmission provider 
determines which specific contingencies will be used for the ATC 
calculation. The common industry practice is to consider the loss

[[Page 32654]]

of each transmission facility at voltage 100 kV and above. However, the 
lack of standards governing transfer analysis allows the transmission 
provider to use its discretion to monitor outages only of facilities at 
230 kV and above, ignoring the limitations that may exist for the loss 
of the facilities at lower voltages, such as 115 kV or 138 kV. 
Consequently, ATC values may vary substantially, with ATC being much 
higher when monitoring contingencies of facilities at 230 kV and above, 
and much lower while monitoring the loss of all facilities (voltage 100 
kV and above).
---------------------------------------------------------------------------

    \119\ Transmission providers do not always know the generator 
used as a source of energy provided under contracts that qualify as 
designated resources; the only requirement is that the network 
customer have an executed contract that commits it to purchase 
noninterruptible power. See Wisconsin Public Power Inc. v. Wisconsin 
Public Service Corp., 84 FERC ] 61,120 at 61,650-51 (1998).
    \120\ Standard TPL-001-0, Table I. Transmission System 
Standards--Normal and Emergency Conditions, NERC Reliability 
Standards for the Bulk Electric Systems of North America (effective 
April 1, 2005).
---------------------------------------------------------------------------

    119. Furthermore, in calculating ATC, transmission providers set 
aside a portion of transfer capability in the form of CBM and/or TRM to 
provide for adequate generation reserves and account for uncertainties 
or contingencies, respectively. Generally, CBM is the amount of firm 
transmission transfer capability held back by the transmission provider 
so that load-serving entities, whose loads are located on the 
transmission provider's system, can access remote generation reserve 
from interconnected systems in times of emergency generation 
deficiencies. Some believe it is necessary for transmission providers 
to set aside a portion of their TTC to ensure that their ties with 
other systems remain available for this purpose. There are no 
consistent industry-wide standards, however, for determining how much 
transfer capability should be set aside as CBM. There is also no common 
approach to whether the capacity is set aside for Native Load 
Customers, as defined in section 1.19 of the pro forma OATT, for retail 
load, or for all load-serving entities. The lack of consistent criteria 
and clarity with regard to the entity on whose behalf CBM has been set 
aside has the potential to result in the transmission provider setting 
aside capacity that it might not otherwise need to, thus increasing 
costs for native load customers and blocking other firm uses of the 
transmission system.\121\
---------------------------------------------------------------------------

    \121\ The Commission has explained that the pro forma OATT 
requires both transmission customers and transmission providers 
using the transmission system to serve network load (including 
bundled retail native load) to designate their resources and loads 
so that the transmission customers and transmission providers would 
have no incentive to designate network resources above their needs 
and, in so doing, tie up valuable transmission capacity. Aquila 
Power Corp. v. Entergy Services, Inc., 90 FERC ] 61,260, reh'g 
denied, 92 FERC ] 61,064 (2000), reh'g denied, 101 FERC ] 61,328 
(2002), aff'd sub nom. Entergy Services, Inc. v. FERC, 375 F.3d 1204 
(D.C. Cir. 2004) (Aquila).
---------------------------------------------------------------------------

    120. Similarly, TRM is the amount of transmission transfer 
capability reserved by the transmission provider to ensure that the 
transmission network will be secure under a reasonable range of 
uncertainties in system conditions. Because TRM and CBM are both 
maintained in part for the loss of generators, there exists the 
possibility of double-counting reliability margins for the loss of the 
same generation.
    121. Moreover, a transmission provider also can use more 
conservative inputs and assumptions for calculating ATC and performing 
system impact studies (that tend to minimize ATC) when it is assessing 
a long-term transmission service request, but use less conservative 
inputs and assumptions (that tend to maximize ATC) when it is 
performing system planning for retail native load. This creates the 
potential for undue discrimination where a transmission provider uses 
one set of data and assumptions to evaluate third party requests and 
another set of data and assumptions to plan its system to serve its own 
load.
Data Exchange Among Transmission Providers
    122. The lack of a consistent ATC calculation methodology combined 
with limited coordination between transmission providers can result not 
only in inefficiencies but unjust and unreasonable terms and conditions 
of service, especially for a customer seeking contiguous transmission 
service from multiple transmission providers. The ATC values posted by 
a transmission provider are often inaccurate for reasons beyond the 
control of the transmission provider. A transmission provider may post 
ATC values in good faith and attempt to provide transmission service 
based on these values only to discover later that the transfer 
capability that it thought was available no longer exists due to 
decisions made by other transmission providers that it did not know 
about at the time it made its calculations. Accurate ATC calculation 
requires reliable and timely information about such things as load, 
generation dispatch, facility outages, and transactions on neighboring 
systems. Transmission providers also may apply differing assumptions 
and criteria to ATC calculations, which may produce wide variations in 
posted ATC values for the same transmission paths. All of these 
considerations make it difficult for an individual transmission 
provider that operates one part of an interconnected grid to calculate 
ATC accurately.
    123. This lack of communication and coordination between 
transmission providers of ATC data can also affect reliability. As 
discussed above, a transmission provider could grant transmission 
service without being aware of the real impact that service may have on 
an adjacent transmission provider's system, thus degrading the 
reliability of the interconnected system. Inaccurate ATC values can 
cause overselling of transfer capability, which can lead to 
curtailments or transmission loading relief (TLR) actions to avoid 
exceeding thermal, voltage, and/or stability limits.
Transparency
    124. As discussed, the lack of a consistent, industry-wide 
methodology for assessing ATC makes undue discrimination difficult to 
detect. This problem is further exacerbated by a lack of transparency 
surrounding the calculation methodology used by transmission providers. 
Although the Commission requires transmission providers to file their 
methodologies for calculating ATC in their tariffs, transmission 
providers often have responded by filing very general narrative 
descriptions of their calculation methodologies (often simply referring 
to the general NERC definition) \122\ without further specification of 
the mathematical algorithm, data inputs, and modeling assumptions used 
to perform the calculation.
---------------------------------------------------------------------------

    \122\ See, e.g., the OATTs of Aquila, Inc., Southern, and Tucson 
Electric Power Company.
---------------------------------------------------------------------------

    125. Other than the description of the ATC methodology provided in 
transmission providers' tariffs, third parties often have limited 
access to information concerning the specific algorithms, data and 
assumptions used by transmission providers to evaluate their ATC, which 
makes it difficult to verify or challenge a transmission provider's ATC 
calculations. The Commission requires each transmission provider to 
calculate and post ATC and TTC values for each posted path.\123\ 
Transmission providers also are required to make publicly available, on 
request, all data used to calculate ATC and TTC for any constrained 
path.\124\ Additionally, transmission providers are required to make 
publicly available, on request, system planning studies or

[[Page 32655]]

network impact studies performed for customers to determine network 
impacts. Furthermore, subsequent to Order Nos. 888 and 889, the 
Commission required each transmission provider to post (and update) the 
CBM value for each path for which it already posts ATC and TTC, as well 
as a narrative explanation of its CBM practices.\125\
---------------------------------------------------------------------------

    \123\ See 18 CFR 37.6 (b) (2005). A posted path is defined as 
any control area to control area interconnection; any path for which 
service is denied, curtailed or interrupted for more than 24 hours 
in the past 12 months; and any path for which a customer requests to 
have ATC or TTC posted. Id. 37.6 (b)(1)(i).
    \124\ Id. 37.6 (b)(2)(ii). A constrained posted path is defined 
as any posted path having an ATC value less than or equal to 25 
percent of TTC at any time during the preceding 168 hours or for 
which ATC has been calculated to be less than or equal to 25 percent 
of TTC for any period during the current hour or the next 168 hours. 
Id. 37.6 (b)(1)(ii).
    \125\ Capacity Benefit Margin in Computing Available 
Transmission Capacity, 88 FERC ] 61,099 (1999) (CBM Order).
---------------------------------------------------------------------------

    126. Yet, despite these requirements, third parties often are 
unable to gain access to sufficient information surrounding a 
transmission provider's ATC calculation methodology. As a preliminary 
matter, we note that while the OASIS requirements regarding the 
availability of information related to ATC and TTC calculations are 
still in effect, they have been affected by restrictions that have been 
placed upon the availability of critical energy infrastructure 
information (CEII) in the interest of national security.\126\ 
Therefore, system planning and network impact studies and models 
typically are no longer available on a transmission provider's OASIS. 
Furthermore, transmission customers are often unable to access other 
information such as load flow base cases and associated files. In sum, 
although existing Commission regulations are intended to provide a 
certain level of transparency, this transparency is undermined by a 
number of factors, including the absence of detailed descriptions of 
the data inputs, assumptions, and criteria used to determine the data 
included in ATC calculations, as well as the inability of customers to 
access certain of this data because of, among other reasons, security 
concerns.
---------------------------------------------------------------------------

    \126\ See Critical Energy Infrastructure Information, Order No. 
630, 68 FR 9857 (Mar. 3, 2003), FERC Stats. & Regs. ] 31,140 (2003), 
order on reh'g, Order No. 630-A, 68 FR 46456 (Aug. 6, 2003), FERC 
Stats. & Regs. ] 31,147 (2003), order on clarification, Order No. 
662, 70 FR 37031 (Jun. 28, 2005), FERC Stats. & Regs. ] 31,189 
(2005); see also 18 CFR 388.113 (2005).
---------------------------------------------------------------------------

Recent Industry Efforts To Improve the Consistency and Transparency of 
ATC Calculations
    127. The industry recently has taken some steps to address the lack 
of consistency and transparency in the way ATC is calculated. NERC 
formed a Long-Term AFC/ATC Task Force to review NERC's standards on 
ATC, which issued a final report in 2005 (NERC Report) \127\ that made 
recommendations for greater consistency and greater clarity in the 
calculation of ATC. The task force also recommended greater 
communication and coordination of ATC information to ensure that 
neighboring entities exchange relevant information. Based on the 
recommendations in the NERC Report, NERC has two Standards 
Authorization Request (SAR) proceedings underway to revise the 
standards on ATC. The first SAR proceeding proposes changes to the 
existing standards on ATC to, among other things, further establish 
consistency (on a regional basis) in the calculation of ATC and to 
increase the clarity of each transmission provider's ATC calculation 
methodology. The second SAR proceeding proposes certain changes to 
NERC's existing standards on the ATC components of CBM and TRM. This 
proceeding also calls for greater regional consistency and transparency 
in how CBM and TRM are treated in transmission providers' ATC 
calculations. Also, based on the recommendations in the NERC Report, 
the North American Energy Standards Board (NAESB) has a proceeding 
underway to develop business practice standards to enhance the 
processing of transmission service requests, which use TTC, ATC and/or 
AFC.
---------------------------------------------------------------------------

    \127\ See supra note 115.
---------------------------------------------------------------------------

    128. Following the release of the NERC Report, the Commission 
issued the ATC NOI \128\ seeking comments on the contents of the NERC 
Report. More specifically, the Commission sought comments on the NERC 
Report's recommendations on areas in which CBM and TRM could be more 
specific and whether these recommendations go far enough in promoting a 
common CBM and TRM methodology within each region. The Commission also 
sought comments on the definitions of ATC, AFC, CBM and TRM. The 
Commission also solicited comments on the advisability of revising and 
standardizing ATC, AFC, TRM and CBM values. In addition, the Commission 
sought comments on the advisability of developing interconnection-wide 
standards for the Eastern Interconnection and WECC. Finally, the 
Commission asked for comments on the most expeditious way to obtain 
industry-wide standards for ATC calculations.
---------------------------------------------------------------------------

    \128\ Supra note 9.
---------------------------------------------------------------------------

    129. Furthermore, in the NOI, the Commission sought comments on 
whether undue discrimination is most likely to occur in areas such as 
ATC calculation where the transmission provider retains discretion as 
to how to implement a particular tariff provision.
Comments
Comments on Consistency
    130. Many commenters express general support for some level of 
increased consistency in ATC calculations.\129\ Some commenters urge 
the Commission to develop a consistent, industry-wide methodology for 
calculating ATC.\130\ Constellation asserts that although transmission 
providers need to be innovative and flexible in many respects, a 
requirement that all transmission providers use the same methodology to 
determine ATC would not only remedy the lack of clarity that surrounds 
these calculations and reservations, but would provide regulatory 
certainty and assist transmission customers in predicting the outcome 
of transmission service requests. This, in turn, Constellation 
suggests, would expand the commercial opportunities for transmission 
customers. According to Alcoa, AWEA and Renewable Energy, the industry-
wide methodology should be a flow-based methodology, rather than a 
contract path methodology because they believe that a flow-based 
analysis provides a more realistic view of actual system usage and 
results in a more accurate assessment of ATC. Exelon further suggests 
that this uniform methodology should also apply to all transmission 
providers, including RTOs.
---------------------------------------------------------------------------

    \129\ E.g., Alcoa, Ameren, AWEA, Calpine, Constellation, 
Cottonwood ATC NOI Comment, ELCON, Exelon, FTC ATC NOI Comment, 
Midwest ISO ATC NOI Comment, Midwest SATS, New York Commission ATC 
NOI Comment, North Carolina Commission, Occidental, South Carolina 
E&G, TAPS, and TransAlta.
    \130\ E.g., Alcoa, AWEA, Constellation, Exelon, Occidental, and 
Renewable Energy.
---------------------------------------------------------------------------

    131. Other commenters argue against a one-size-fits-all approach, 
but rather express a preference for greater uniformity at a regional 
level to recognize regional differences.\131\ These commenters suggest 
that due to differences in transmission systems or regions, it may not 
be practical or possible to standardize the ATC calculation methodology 
on an industry-wide basis. For example, Powerex cautions that 
nationwide standardization may not take into account the unique 
characteristics of particular systems or regions, such as the 
differences attributable to the West's contract-path model and the 
East's flow-based model, as well as differences attributable to the 
primarily hydro-

[[Page 32656]]

based systems in the Pacific Northwest.\132\ Similarly, TANC argues 
that flowgate terminology and application in ATC calculation should not 
be required in the West because it does not adequately represent the 
nature of the many transmission constraints in the West. Other 
commenters caution that too much uniformity of the ATC calculation 
methodology could have an adverse effect on grid reliability.\133\ In 
addition, some commenters urge the Commission not to adopt an ATC 
methodology that is so prescriptive that it inhibits new or better 
practices or imposes a wholesale revision of accepted market designs 
and processes that are working within established markets.\134\
---------------------------------------------------------------------------

    \131\ E.g., Alberta Intervenors, APPA, Bonneville, International 
Transmission, ISO/RTO Council, LDWP, MidAmerican, Nevada Companies, 
Powerex, Progress Energy, Public Generating Pool, Public Power 
Council, Salt River, Santa Clara, Snohomish, Tacoma Power, TANC, and 
TDU Systems.
    \132\ Accord LDWP ATC NOI Comment, Public Power Council, Salt 
River, Snohomish, Tacoma, and TANC.
    \133\ E.g., NERC ATC NOI Comment, Public Power Council, and TVA.
    \134\ E.g., ISO/RTO ATC NOI Comment and Powerex.
---------------------------------------------------------------------------

    132. Several commenters argue against any efforts to further 
standardize ATC calculations.\135\ In its comments filed in the ATC NOI 
proceeding, LDWP asserts that the alleged problems with ATC are 
overstated. Moreover, it argues, the benefits of squeezing additional 
ATC from existing systems have not been established given that 
transmission customers can already request any capacity they need 
regardless of the posted ATC and transmission providers are required to 
make a good-faith effort to evaluate each request. Several commenters 
argue that the circumstances of individual transmission customers vary 
and often ATC calculations rely on the individual transmission 
provider's knowledge of its facilities and system conditions.\136\ For 
example, Southern contends that too many factors go into the 
calculation of ATC to make the adoption of a static set of standards 
feasible. In fact, Southern and EEI maintain, standardization of ATC 
calculations is inconsistent with maintaining reliability because the 
circumstances of transmission providers vary significantly, and they 
must operate their systems based on their specific circumstances. In 
addition, LG&E maintains that standardizing ATC will not necessarily 
eliminate the need for TLR procedures to deal with load forecast errors 
and unplanned generation and transmission outages. Furthermore, some 
commenters argue that increased uniformity could impose significant 
costs upon utilities.\137\
---------------------------------------------------------------------------

    \135\ E.g., Cinergy, EEI, LG&E, LDWP ATC NOI Comment, National 
Grid, PPL, Public Generating Pool, San Diego G&E, Southern, TVA, and 
Xcel.
    \136\ E.g., Southern and TVA.
    \137\ E.g., International Transmission and LG&E.
---------------------------------------------------------------------------

    133. Some commenters urge the Commission to increase the 
consistency of the elements of the ATC calculation, such as the kind of 
data inputs that transmission providers consider when evaluating ATC--
including load levels, generator outage information, transmission 
outage information and generation dispatch information.\138\ Exelon 
also urges the Commission to establish the assumptions that 
transmission providers use in their ATC methodologies--such as how 
transmission reservations are accounted for and which reservations to 
model. Exelon also cites an example of modeling transaction 
counterflows, noting that uniform rules for data inputs are needed to 
ensure that transaction counterflows are modeled identically in both 
the planning and ATC/AFC calculation processes. In addition, commenters 
urge the Commission to establish the procedures for determining ATC 
(and its components) and to require a transmission provider to show 
that it has properly followed all required procedures.\139\ Among other 
things, commenters suggest that the Commission should establish how 
frequently ATC is calculated, how frequently inputs are updated, 
require transmission providers to determine AFC instead of ATC, and 
require transmission providers to recognize all third-party flowgates 
that are requested to be monitored. In addition, several commenters 
state that the Commission should require that the methodology and 
inputs for ATC calculations be consistent with the transmission 
provider's planning or operating criteria.\140\
---------------------------------------------------------------------------

    \138\ E.g., Exelon and TDU Systems.
    \139\ E.g., Ameren and Exelon.
    \140\ E.g., Exelon, ISO/RTO ATC NOI Comment, MISO, and NERC.
---------------------------------------------------------------------------

    134. Several commenters urge the Commission to allow the industry, 
working through NERC and NAESB, to complete efforts already underway to 
further increase consistency of ATC (and its components), as well as 
certain related business practices.\141\ However, many of these 
commenters urge the Commission to give the industry, working through 
these organizations, specific guidance on what issues to decide and the 
parameters for the discussions.\142\ Furthermore, commenters state that 
the Commission should establish a date certain for completion of these 
industry efforts,\143\ and should also take an active role in the 
process.\144\
---------------------------------------------------------------------------

    \141\ E.g., Ameren, APPA ATC NOI Comment, Duke, EEI, Exelon, 
International Transmission Company ATC NOI Comment, ISO/RTO Council 
ATC NOI Comment, KCP&L, MidAmerican ATC NOI Comment, MISO ATC NOI 
Comment, Progress Energy, Southern, TAPS, TDU Systems, TransAlta, 
and WestConnect ATC NOI Comment.
    \142\ E.g., APPA ATC NOI Comment and International Transmission 
ATC NOI Comments.
    \143\ E.g., Duke and Exelon.
    \144\ E.g., APPA ATC NOI Comment, TAPS, and TransAlta.
---------------------------------------------------------------------------

    135. Other commenters suggest that the Commission should require 
that an independent entity develop and/or monitor a transmission 
provider's ATC methodology and its ATC calculations.\145\ For example, 
Constellation states that it does not believe that the solution is to 
prohibit the transmission provider entirely from exercising its 
discretion, but instead to require transmission providers to retain an 
independent entity that can perform certain functions on a consistent, 
unbiased basis. In addition, the Arkansas Commission asserts that 
section 1281 of EPAct 2005 \146\ gives the Commission the authority to 
require the use of an independent coordinator of transmission to 
provide independent and verifiable transparency over critical Order No. 
888 functions, such as ATC calculations.
---------------------------------------------------------------------------

    \145\ E.g., Arkansas Commission, Calpine, Constellation, EPSA, 
New York Commission, Occidental, and TDU Systems.
    \146\ EPAct 2005 sec. 1281(to be codified at section 220 of the 
FPA, 16 U.S.C. 824t), which concerns electricity market transparency 
rules.
---------------------------------------------------------------------------

    136. Several commenters specifically address the lack of 
consistency in the industry on the definition and use of CBM and TRM. 
For example, TAPS notes that NERC does not require any transmission 
provider to reserve CBM. In addition, TAPS states, even in those 
regions that use CBM, there is often no regional methodology; it is up 
to the vertically integrated transmission provider to determine whether 
it wants to reserve CBM at all and at which interfaces, with no 
effective review of that determination. TAPS also states that TRM 
should be clearly defined and, if truly required for reliability, then 
all transmission providers should reserve it. According to TAPS, the 
Commission should define TRM in a manner that leaves no discretion as 
to whether, where, and how much capacity to set aside. EPSA also notes 
that there is a disconnect between the planning and expansion processes 
and the assumptions transmission providers use to calculate CBM and 
TRM.
    137. TANC states that the Commission should closely examine the 
necessity of CBM in ATC calculations. Bonneville argues that there 
should only

[[Page 32657]]

be one commercial margin instead of multiple margins (TRM, CBM, and 
others).
Comments on Data Exchange Among Transmission Providers
    138. Several commenters argue that the Commission should establish 
standards for resolving seams issues between transmission providers 
where each transmission provider uses a different methodology for 
calculating ATC.\147\ Constellation and BC Transmission assert that 
when different transmission providers have different methods for 
determining ATC, this can lead to inefficiencies, including market 
confusion, lost sales/purchase opportunities, and unnecessary 
curtailments.
---------------------------------------------------------------------------

    \147\ E.g., BC Transmission, Constellation, Exelon, NY 
Transmission, Renewable Energy, and TDU Systems.
---------------------------------------------------------------------------

    139. Commenters identify various elements of the ATC calculation 
methodology that they argue should be more consistent. For example, BC 
Transmission states that some of the elements that are calculated 
differently at the seams include the level of TRM, the level of CBM, 
the approach regarding the sale (or not) of TRM as non-firm capacity, 
assumptions regarding controlling interchange and assumptions regarding 
operating conditions. Similarly, MidAmerican in its response to the ATC 
NOI suggests that greater coordination is needed on partial path 
review, policies for decrementing AFC and redispatch policies. For 
example, MidAmerican references problems associated with coordination 
between transmission providers on partial path treatment. Specifically, 
when transmission service involves a path across multiple systems, a 
given flowgate may be evaluated several times by various providers on 
the transmission path. Because of a lack of coordination between these 
providers, AFC on the flowgate may be decremented multiple times for 
the same transmission service request, and service may be denied even 
when the true available capacity on the flowgate is sufficient to allow 
the request to be granted. Exelon also states that certain data inputs 
must be coordinated across all transmission providers in an 
interconnection including load levels, transmission outages, generation 
outages and generation dispatch. In addition, Exelon states, the 
Commission should establish how transmission providers account for 
transmission reservations in an ATC/AFC calculation.
    140. Moreover, NY Commission suggests that this problem goes beyond 
the non-independent transmission providers. According to NY Commission, 
in order for RTOs to properly determine tie flow limits, they need 
access to certain information from the control region on the other side 
such as load levels and distributions, generator dynamic capability and 
expected outputs, phase shifter positions and standard contingencies 
required by that control area. In addition, NY Commission states, these 
inputs need to be updated daily.
    141. Finally, Alcoa states that the potential for underestimating 
ATC is likely another consequence of the fundamental conflict between 
the contract path model and the electricity path model of contracting 
for electric energy. According to Alcoa, outside of ISO/RTO systems, 
utilities may not have enough data available to compute ATC, since they 
may not be able to accurately complete all relevant parallel path 
transactions.
Comments on Transparency
    142. Commenters are overwhelmingly in favor of greater transparency 
in the ATC calculation methodology to provide more assurance that a 
transmission provider is not performing its ATC calculations in an 
inconsistent or unduly discriminatory manner.\148\ EEI suggests that 
transmission providers could make their base case load flow studies on 
which they base their calculation of ATC available to transmission 
customers, subject to security and confidentiality protections. Other 
commenters state that greater transparency could be achieved through 
the imposition of additional posting requirements on OASIS.\149\ These 
commenters argue that the Commission should require transmission 
providers to post their discrete methodologies and algorithms for 
evaluating ATC, as well as their transmission modeling information and 
their various assumptions. Commenters further suggest that transmission 
providers should be required to provide information regarding planned 
outages, and to ensure consistent treatment of outage information 
between control areas.\150\
---------------------------------------------------------------------------

    \148\ E.g., Alcoa, Ameren, APPA, Calpine, CEOB, Cinergy, 
Constellation, Cottonwood, Duke, EEI, ELCON, HQ Energy, LDWP, 
MidAmerican, Midwest ISO, Midwest SATs, Powerex, PPL, Progress 
Energy, Public Generating Pool, Public Power Council, Salt River, 
Southern, TANC, TAPS, TDU Systems, TransAlta, and TVA.
    \149\ E.g., Calpine and PPL.
    \150\ E.g., H.Q. Energy and Powerex.
---------------------------------------------------------------------------

    143. In its reply comments, Southern acknowledges that greater 
transparency would reduce concerns of undue discrimination, but 
cautions the Commission against imposing unnecessary and duplicative 
posting requirements and notes that much of the information that 
commenters have asked the Commission to make transparent is in fact 
already publicly available through a variety of sources.
    144. In addition, some commenters urge the Commission to impose 
meaningful reporting requirements.\151\ In this regard, Constellation 
asserts that the Commission should modify the pro forma OATT to require 
that transmission providers post systematic, timely and accurate 
reporting of certain service metrics such as transaction requests 
approved, rejected, confirmed, and curtailed. Similarly, Cottonwood 
states that transmission providers should be required to provide 
information detailing why a particular transmission request was denied 
and whether there are other available alternatives. In addition, 
several commenters argue that transmission providers also should be 
required to post their relevant business practices, operating 
standards, protocols and internal guidelines that affect transmission 
service.\152\ TDU Systems also urge the Commission to require 
transmission providers to explain why transactions are allowed to flow 
even when the posted ATC value was zero.
---------------------------------------------------------------------------

    \151\ E.g., Constellation, Cottonwood, and TDU Systems.
    \152\ E.g., Powerex and TransAlta.
---------------------------------------------------------------------------

    145. EPSA argues that capacity is unnecessarily held from the 
market when transmission providers reserve excessive amounts for their 
native load and when they fail to make capacity available through 
redispatch. EPSA states, however, that there is no way of knowing 
whether there is a hoarding problem because there is no requirement to 
post the necessary real time information on transmission utilization, 
and recommends a requirement to post such information. Powerex contends 
there is an incentive for transmission providers to hoard because 
grandfathered or other firm rights held by the transmission provider to 
serve native load are subsequently used for wholesale marketing 
purposes. It further states, however, that evidence of anticompetitive 
practices is difficult to obtain because of a lack of transparency. 
Powerex supports increased requirements for both uniform and 
transparent ATC calculation.
    146. Several commenters urge the Commission to establish compliance 
review procedures and impose sanctions for violations to ensure that 
transmission providers are accountable

[[Page 32658]]

for ensuring that their ATC calculations are correct.\153\ In its 
response to the ATC NOI, Cottonwood states that the Commission should 
develop specific tests (benchmarks) to monitor transmission providers' 
performance. In addition, HQ Energy states that the Commission should 
conduct periodic reviews of whether non-independent transmission 
providers have properly calculated and allocated ATC. ELCON states that 
the Commission should place the burden of proof to depart from its ATC 
methodology on the transmission provider and include specific penalties 
in the tariff for transmission providers that are found to be in 
violation.
---------------------------------------------------------------------------

    \153\ E.g., Cottonwood ATC NOI Comment, ELCON, HQ Energy, NRECA, 
Occidental, and Powerex.
---------------------------------------------------------------------------

    147. HQ Energy and Powerex also state that the Commission should 
require transmission providers to ensure that staff is available at all 
times to respond to customer inquiries regarding real-time 
transactions.
Discussion
    148. We propose to address the potential for remaining undue 
discrimination in the determination of ATC by requiring industry-wide 
consistency and transparency of certain definitions, data, modeling 
assumptions and components of ATC. We propose to provide general 
guidance regarding the aspects of ATC calculation that we believe 
should be more consistent and direct public utilities, working through 
NERC and NAESB, to use our guidance to revise the relevant standards 
and business practices. In addition, we propose to require increased 
detail in the pro forma OATT regarding the method of calculating ATC 
and to amend our OASIS regulations to require increased transparency.
    149. Though NERC and NAESB currently are working on certain 
proposals to address the problems we have identified,\154\ we are 
concerned that without guidance, direction and a firm deadline, these 
industry developments may not succeed due to other conflicting 
priorities. We believe that the existing NERC and NAESB processes are 
well-suited to achieving greater consistency in ATC calculations. It is 
our expectation that NERC and NAESB will expand on the work they have 
already undertaken to achieve the goals we propose to set out for them.
---------------------------------------------------------------------------

    \154\ We understand that two NERC standard authorization 
requests related to ATC/ TTC/AFC and CBM/TRM were approved earlier 
this year, and that drafting of the standards' revision is underway. 
We further understand that NAESB has a concurrent drafting effort 
underway for associated business practices that will follow a 
coordinated path with the NERC process. See http://www. nerc.com/

filez/ standards/MOD-V0-Revision. html.
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    150. We propose to take this action pursuant to our obligation 
under FPA section 206 to remedy undue discrimination in the provision 
of transmission service. Transmission providers in general enjoy 
substantial discretion in establishing and interpreting the specific 
algorithms, data, and assumptions needed to assess ATC. Though we do 
not believe it is possible or necessary to entirely eliminate 
discretion, unchecked discretion affords a transmission provider the 
ability and opportunity to discriminate in its favor (and its 
affiliate's favor) against third parties in how it calculates and 
allocates ATC and, therefore, may be unjust, unreasonable, unduly 
discriminatory and preferential. Transmission providers have an 
incentive to understate ATC on transmission paths that would be 
valuable to power sellers that are competitors to the transmission 
providers' own (or their affiliates') power sales. Where transmission 
congestion exists, the methodology for calculating ATC will effectively 
determine whether competitors have access to the transmission grid, and 
the lack of any consistent methodology for calculating ATC gives 
transmission providers excessive discretion in making this 
determination.
    151. The lack of consistency and detail in the determination of ATC 
can facilitate undue discrimination in a variety of ways. Transmission 
providers may use generation dispatch assumptions that result in 
limited capacity being available to merchant generators. They also may 
use different inputs and assumptions for purposes of calculating ATC 
for third parties than they do for system planning for retail native 
load. As noted above, a transmission provider could reduce a facility 
rating or model certain facilities as out of service, which would have 
the effect of underestimating TTC. In determining ETC, transmission 
providers have discretion to determine the capacity needed and set 
aside for native load usage. Each of these exercises of discretion has 
a significant effect on ATC.
    152. The lack of transparency into how a transmission provider 
calculates and allocates its ATC (including all assumptions and data 
inputs) makes it difficult to detect discriminatory behavior. This lack 
of transparency frustrates and increases the costs of compliance and 
enforcement efforts. Many transmission providers have urged the 
Commission to provide greater clarity in the rules for OATT 
service,\155\ particularly given the threat of the Commission's new 
civil penalty authority.
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    \155\ E.g., Ameren, APPA ATC NOI Comments, Duke, EEI, Exelon, 
International Transmission Company ATC NOI Comments, ISO/RTO Council 
ATC NOI Comments, KCP&L, MidAmerican ATC NOI Comments, MISO ATC NOI 
Comments, Progress Energy, Southern, TAPS, TDU Systems, TransAlta, 
and WestConnect ATC NOI Comments.
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    153. In addition to our preliminary finding that the lack of 
consistent, industry-wide ATC calculation standards is unjust and 
unreasonable under FPA section 206, we believe that it poses a threat 
to the reliable operation of the bulk-power system. A transmission 
provider needs to know how much electricity its system can carry. The 
lack of a consistent, industry-wide methodology for evaluating ATC and 
the lack of data sharing among transmission providers often leads to 
problems in determining the appropriate ATC value. Despite a 
transmission provider's good faith attempt to calculate and post 
accurate ATC levels, it can find that transmission that it thought was 
available on its system no longer exists because it was unaware of 
decisions by other transmission providers. This, in turn, can threaten 
the reliable operation of the interconnected transmission system.\156\
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    \156\ According to NERC, ``the lack of standardization and more 
ignificantly, limited coordination can negatively impact both the 
market, through the need for a large number of [TLR] actions (or 
curtailments in WECC) and, on occasion, reliability when even the 
use of TLRs provides insufficient relief on some critical 
interfaces.'' See NERC Report at 1.
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    154. As a result of reliability effects of inconsistent ATC 
calculations, our proposal for greater consistency and transparency 
also is supported by our new authority under section 215 of the FPA, 
which gives the Commission jurisdiction to certify an Electric 
Reliability Organization (ERO) and to approve reliability standards 
that are just, reasonable, not unduly discriminatory or preferential, 
and in the public interest. The Commission also has authority to order 
the ERO to submit a reliability standard that the Commission considers 
appropriate to implement FPA section 215.\157\ On April 4, 2006, NERC 
submitted an application to be certified as the ERO, as well as 
proposed reliability standards.\158\ In this NOPR, we direct our 
guidance to public utilities and recommend that they implement our 
direction by working with NERC. However, this is not intended to 
prejudge the outcome of the ERO proceeding. Though the Commission

[[Page 32659]]

will act independently on the reliability standards proposed by NERC in 
Docket No. RM06-16-000, we believe it is prudent to provide our 
guidance now on NERC's reliability standards related to ATC by 
providing specific direction on what should be more consistent and a 
timeframe for completion of NERC's efforts.\159\ As we indicated above, 
the lack of consistency, data exchange and transparency in ATC 
calculations not only can increase the opportunities for undue 
discrimination but also can threaten reliability. We therefore believe 
that Commission action pursuant to FPA section 215 may be appropriate 
on reliability standards related to ATC calculation. Any action on 
these reliability standards that is taken in Docket No. RM06-16-000 
(the ERO standards rulemaking) will be coordinated and consistent with 
our determinations regarding ATC calculation in this proceeding.\160\
---------------------------------------------------------------------------

    \157\ Section 215(d)(5).
    \158\ See Docket Nos. RR06-1-000 and RM06-16-000.
    \159\ In this NOPR, we direct our guidance to NERC, though the 
reliability standards relating to ATC ultimately will be adopted by 
the ERO.
    \160\ We note that Commission staff recently released a 
preliminary assessment of the proposed ATC-related reliability 
standards, stating that they ``may result in unnecessary regional 
variations not justified by technical differences and inconsistent 
applications.'' Staff Preliminary Assessment of the North American 
Reliability Council's Proposed Mandatory Reliability Standards at 80 
(May 11, 2006).
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Consistency
    155. The Commission proposes to require public utilities, working 
through NERC, to develop the standards we set forth below within 6 
months of the final rule in this proceeding. Consistent with NERC's 
existing efforts, we propose to require the development of standards 
for: (1) ATC/AFC, TTC/Total Flowgate Capacity (TFC), ETC, CBM, and TRM 
calculation methodologies, (2) data inputs, (3) modeling assumptions, 
(4) ATC calculation frequency, and (5) data exchange and coordination 
processes. We further propose to require public utilities, working 
through NAESB, to work with NERC to identify the appropriate business 
practices to complement the standards developed by NERC. We discuss 
below each of the elements for which we propose to require more 
consistency. We seek comment on these elements of the ATC calculation 
and, in particular, whether certain elements are more susceptible to 
further consistency than others and whether certain elements should be 
prioritized over others because they represent the source of most 
disputes between transmission providers and customers. We recognize the 
need to focus on those elements of the ATC calculation that are most 
susceptible to further consistency and most important in terms of 
eliminating opportunities for undue discrimination.
    156. The Commission recognizes that transmission providers use 
several basic types of ATC calculation methodologies (with various 
permutations), and does not believe that a single ATC calculation 
methodology must be applied by all transmission providers.\161\ 
However, we agree with commenters who argue that the amount of 
discretion in the existing ATC calculation methodologies gives 
transmission providers the ability and opportunity to unduly 
discriminate against third parties. Accordingly, we propose to achieve 
greater consistency in ATC calculations by directing the development of 
consistent definitions of the components of ATC, as well as consistent 
data inputs, data exchange and coordination protocols, and modeling 
assumptions, as discussed further below. We believe that this level of 
consistency will go a long way toward producing more coherent and 
uniform determinations of ATC across a region, thereby helping to 
eliminate the potential for undue discrimination.\162\
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    \161\ For example, there are two primary ATC calculation 
methodologies: The contract path approach and the flowgate approach. 
See generally P 115. However, the ATC values that result from 
application of either method should largely be the same if 
consistent data inputs and modeling assumptions are used.
    \162\ As discussed further below, for consistency to be fully 
effective, it should be coupled with increased transparency. As 
such, we also propose greater transparency below.
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    157. We propose to direct public utilities, working through NERC, 
to develop consistent practices for TTC/TFC calculation methodologies. 
We recognize that the NERC reliability regions have historically 
calculated transfer capability using different approaches.\163\ 
However, we expect that guidelines can be developed for the calculation 
of transfer capability that use a common approach to model power 
transfers. In addition, we believe that the criteria used for 
identifying flowgates and determining TTC/TFC can be more consistent.
---------------------------------------------------------------------------

    \163\ One approach models power transfers by scaling up/down the 
load, a second approach scales generation up/down, and yet another 
approach uses a combination of changes in load and generation.
---------------------------------------------------------------------------

    158. The Commission believes that the lack of consistency of ETC 
permits too much discretion in determining how much capacity a 
transmission provider sets aside for native load, including its network 
customers. We believe that the development of an industry-wide 
methodology can limit this discretion. Therefore, we propose to require 
the development of a consistent methodology for determining the 
capacity needed and set aside for native load usage. In addition, we 
propose that accounting for transmission reservations in an ATC/AFC 
calculation also should be more consistent. Presently, there are two 
main methods in use. One method models all ``appropriate reservations'' 
\164\ in the power flow base case model. The other method models only 
those reservations that are expected to be actually scheduled and 
accounts for others by decrementing flowgate AFC. It is important for 
consistency to use the same calculation technique when modeling these 
types of reservations. Therefore, we propose that public utilities, 
working through NERC, establish and specifically identify which 
reservations they use in determining ETC.
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    \164\ ``Appropriate reservations'' takes into account the time 
frame (e.g., yearly, monthly) and ATC product (e.g., firm, non-firm) 
being calculated.
---------------------------------------------------------------------------

    159. The Commission has previously addressed the lack of a 
consistent industry-wide methodology for determining CBM. Following a 
two-day technical conference, the Commission held in the CBM Order 
\165\ that transmission providers continue to wield significant 
latitude in interpreting how CBM is determined. The Commission directed 
that the CBM set-aside be more transparent, more accurate, and more 
widely available.\166\ We remain concerned, however, that transmission 
providers have preferential access to the interface capacity that is 
set aside. This interface capacity is paid for by all transmission 
customers whether or not they receive a benefit from the set-aside. In 
general, we believe that the latitude associated with CBM undermines 
the certainty and transparency that is needed for non-discriminatory, 
open-access transmission service.
---------------------------------------------------------------------------

    \165\ Capacity Benefit Margin in Computing Available 
Transmission Capacity, 88 FERC ] 61,099 (1999) (CBM Order).
    \166\ CBM Order at 61,237-38.
---------------------------------------------------------------------------

    160. The current pro forma OATT offers two means of reserving 
transfer capability, either of which implicitly provides some financial 
discipline to overreservations. The first is the requirement to 
designate a network resource on the other side of the interface and 
assume the associated financial responsibility of either owning the 
resource or executing a firm power purchase agreement. The other is to 
contract for firm point-to-point service on the interface, which 
requires the payment of a point-to-point reservation charge. In either 
case there is a disincentive to reserving transfer capability simply to 
prevent someone else from using it on a firm basis. With

[[Page 32660]]

these processes in mind, the Commission has identified three possible 
options to provide the necessary certainty, transparency, and financial 
discipline necessary to remedy the potential for undue discrimination 
associated with inappropriate ATC set-asides for CBM. These options 
need not be mutually exclusive.
    161. One option is to require that clear standards be developed for 
how the CBM value should be determined and allocated across 
transmission paths, and for which customers CBM should be used.\167\ 
Consistent with the standards development process that is already in 
progress, we propose that these standards specify how CBM should be 
reserved to allow any load-serving entity to meet generation 
reliability criteria on a nondiscriminatory basis. In addition, we 
propose that NERC specify emergency generation deficiency conditions 
during which a load-serving entity will be allowed to use the transfer 
capability reserved as CBM. We believe that CBM should be reserved only 
when there is insufficient local generation capacity to meet generation 
reliability standards, and it should always have a zero value in the 
calculation of non-firm ATC.
---------------------------------------------------------------------------

    \167\ NERC has already contemplated developing a standard to 
address CBM issues. See http://www.nerc.com/~filez/standards/MOD-V0-Revision.html
.

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

    162. Another approach may be to develop a specific charge for 
setting aside ATC for CBM. This approach would treat CBM as a service 
that would be available to customers serving load within the 
transmission provider's service area. To do this, the Commission would 
propose that an entity for which transfer capability has been set aside 
to meet generation reliability criteria be charged a separate rate for 
this service. We seek comment on this proposal to charge a separate 
rate, as well as comment on the potential impacts on overall rates and 
revenues. We also seek comment on whether there are credible situations 
in which the proposal would not be feasible. Commenters are encouraged 
to provide specific examples.
    163. A third option may be to eliminate CBM and replace it with 
specific transfer capability reservations associated with designated 
network resources. In several cases, the Commission addressed instances 
when transmission providers had taken advantage of their ability to 
preserve interface capability to serve their own load while limiting 
the ability of competing suppliers to access customers on their 
systems. In these orders, the Commission position was that if a utility 
wanted to use firm transmission capacity on an interface to serve its 
native load, it was required to designate a network resource associated 
with that capacity on the other side of the interface pursuant to the 
requirements of the pro forma OATT.\168\ Specifically, the Commission 
stated that the pro forma OATT requires the transmission provider to 
designate all network resources, including those acquired for the 
purpose of meeting generation reserves, in the same manner as network 
customers do.\169\ The retention of this obligation would require the 
transmission provider to replace any existing set-aside of firm 
transfer capability as CBM with reservations for specific designated 
resources. We seek comment on the reasonableness of eliminating CBM and 
any impacts on the reliable operation of the transmission system. 
Commenters are encouraged to provide specific examples of transmission 
providers that currently do not use CBM and, alternatively, conditions 
under which CBM must be used. We also ask for comments on how 
eliminating CBM would affect the ability of load-serving entities to 
meet existing generation reliability adequacy requirements.
---------------------------------------------------------------------------

    \168\ See Aquila supra note 121; see also Morgan Stanley Capital 
Group v. Illinois Power Co., 83 FERC ] 61,204, clarified, 83 FERC ] 
61,299 (1998), order on reh'g, 93 FERC ] 61,081 (2000).
    \169\ Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public 
Service Corp., 83 FERC ] 61,198 at 61,857-58 (1998).
---------------------------------------------------------------------------

    164. The Commission proposes that public utilities, working through 
NERC, develop clear standards for how TRM is determined, allocated 
across transmission paths, and used. In addition, we propose to require 
that the standards ensure that there will be no contingency double-
counting when calculating TRM, TTC and CBM. We also propose that the 
standards developed should specify the uncertainties that are accounted 
for in TRM and the methods used to determine their impacts on TRM 
values. The Commission proposes that TRM can be used to accommodate 
uncertainties such as: (1) Load forecast and load distribution error, 
(2) variations in facility loadings, (3) uncertainty in transmission 
system topology, (4) loop flow impact, (5) variations in generation 
dispatch, including intermittent resources, (6) automatic sharing of 
reserves, and (7) other uncertainties identified through the NERC 
forums.
    165. The Commission acknowledges that accurate data and system 
models are essential to accurately simulate the performance of the 
electric system when calculating ATC. The data and models used by the 
transmission provider should be consistent, to the maximum extent 
practicable, with the data and models used for the planning, operation, 
and expansion of the transmission system. While NERC's current ATC-
related standards (MOD-001--MOD-009) require that steady state and 
dynamic data be submitted and that steady state and dynamic system 
models be prepared, there is no requirement to periodically benchmark 
these models and appropriately modify them against actual system 
events.\170\ Therefore, the Commission proposes that public utilities, 
working through NERC, modify the ATC-related standards to incorporate a 
requirement for the periodic review and modification of these models 
(including load flow base cases, short circuit data, transient and 
dynamic stability simulation data, contingency,\171\ subsystem and 
monitoring files, and production cost models), in order to ensure that 
they are up to date.
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    \170\ See U.S.-Canada Power System Outage Task Force, Final 
Report on the August 14, 2003 Blackout in the United States and 
Canada: Causes and Recommendations, Recommendation Number 24 (April 
2004). See http://reports.energy.gov/.

    \171\ Contingency files should contain information on special 
protection schemes and remedial action plans.
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    166. Modeling assumptions are a crucial element in the calculation 
of ATC. The Commission proposes that public utilities, working through 
NERC, develop consistent assumptions for use in ATC determinations. The 
Commission proposes that the assumptions used in the calculation of ATC 
be made consistent among transmission providers, to the maximum extent 
practicable. In general, the Commission believes that the assumptions 
used in the determination of ATC should be consistent with those used 
when planning the operation and expansion of the transmission system. 
This is necessary to remedy the potential for undue discrimination 
between the manner in which a transmission provider plans and operates 
its system to serve native load and the manner in which it calculates 
ATC for service to third parties. Consequently, the models for short- 
and long-term ATC calculation should be developed using consistent 
assumptions regarding the load level, generation dispatch, transmission 
and generation facilities maintenance schedules, contingency outages 
and topology as those used in the planning for operation and expansion. 
In addition, the long-term ATC models should rely to the maximum extent 
practicable upon the

[[Page 32661]]

same assumptions regarding new transmission and generation facilities 
additions and retirements as those used in the planning for expansion.
    167. More specifically, the Commission proposes to direct public 
utilities, working through NERC, to establish consistent assumptions 
that are related to the modeling of: (1) Representative load levels, 
(2) generation dispatch, (3) transmission reservations and (4) 
counterflows, in addition to any other modeling assumptions identified 
by NERC. Regarding the assumptions used for load level modeling in the 
ATC calculation, the Commission proposes to require all transmission 
providers to have a consistent approach to modeling of load levels. 
With respect to the base generation dispatch, we propose that public 
utilities, working through NERC, establish a method for determining 
which generators should be modeled in service, including guidance on 
how independent generation should be considered. With respect to 
modeling of particular transactions, the Commission believes that a 
consistent approach is needed on how to simulate power flows from 
points of receipt to points of delivery when sources are unknown. 
Accounting for transmission reservations in an ATC/AFC calculation also 
should be consistent.\172\ We note that the purpose of more consistent 
modeling assumptions is to eliminate discretion and the potential for 
undue discrimination. This proposal is not intended to change the 
manner in which native load customers are served. We seek comment on 
whether (and, if so, how) this proposal would affect service to native 
load customers.
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    \172\ Currently, one method models all appropriate reservations 
in the power flow base case model, when another models only those 
reservations that are expected to be scheduled, and accounts for 
others by decrementing flowgate AFC.
---------------------------------------------------------------------------

    168. The Commission also supports the development of clear 
standards on how often ATC/AFC and its individual components are 
calculated and updated. The Commission proposes that public utilities, 
working through NERC and NAESB, develop standards requiring that the 
calculation be performed on a consistent time interval among 
transmission providers and in a manner that closely reflects the actual 
topology of the system concerning generation and transmission outages, 
load forecast, interchange schedules, transmission reservations, 
facility ratings, and other necessary data. The Commission also 
supports uniform updating of ATC values and components by adjacent 
control areas.
    169. The Commission believes that significant improvements in the 
communication, coordination, and exchange of data across all 
transmission providers in an interconnection are needed to produce 
accurate determinations of ATC. Therefore, we propose that public 
utilities, working through NERC, develop consistent protocols that 
would enable and require the exchange of data among transmission 
providers. We propose that the following data, at a minimum, should be 
exchanged among transmission providers for the purposes of ATC 
modeling: (1) Load levels, (2) transmission planned and contingency 
outages, (3) generation planned and contingency outages, (4) base 
generation dispatch, (5) existing transmission reservations, including 
counterflows, (6) ATC calculation frequency, and (7) source/sink 
modeling identification. In addition, NERC may identify other data 
needs through the standards development process. We seek comment as to 
how much data sharing is workable; whether there are additional data 
that should be provided; whether access to such data should be limited 
to transmission providers; and if there are existing forums by which 
these or similar data are already shared.
    170. In order to facilitate the process for achieving consistency 
in ATC calculations we have proposed in this NOPR, the Commission 
directs Staff to hold a technical conference. The technical conference 
will be transcribed to provide the Commission and NERC a record of the 
comments received at the conference. The Commission will provide 
further guidance regarding the date of the technical conference and the 
topics it intends to address at the technical conference in a 
subsequent notice.
Transparency
Pro forma OATT
    171. Though the Commission's requirement that a transmission 
provider describe its ATC calculation methodology in its OATT has not 
changed, that requirement has been interpreted in various ways. Some 
transmission providers post a detailed explanation of how they 
calculate ATC, while other transmission providers post very general 
descriptions that fail to offer sufficient detail for third parties to 
understand how ATC has been derived. The Commission is concerned that 
the lack of transparency in some of the descriptions provided by 
transmission providers gives these transmission providers too much 
discretion to change ATC practices without sufficient oversight and 
review. The Commission also is concerned that this lack of transparency 
could allow transmission providers to unduly discriminate against their 
competitors when allocating transmission service. We agree with 
commenters that greater transparency is needed into how transmission 
providers calculate and allocate ATC. Accordingly, in order to ensure 
that transmission service is provided in a nondiscriminatory manner, we 
propose to require transmission providers to take certain measures to 
make their ATC calculation process more transparent. We believe that 
these proposed changes will give transmission customers access to 
sufficient information to be able to examine the integrity of the 
process. Moreover, our proposal for greater consistency in the way ATC 
is calculated should aid in transparency because there will be far 
fewer differences in the way individual transmission providers 
calculate ATC. This will make it less difficult to determine whether 
ATC is being calculated in an unduly discriminatory manner.
    172. Specifically, we propose to require transmission providers to 
include, at a minimum, in Attachment C of their OATT, the following 
information concerning their ATC calculation methodology (including the 
calculation of AFC, if applicable). First, we propose to require 
transmission providers to state their specific mathematical algorithm 
used to calculate their firm and non-firm ATC (and AFC, if applicable) 
for their scheduling horizon (same day and real-time), operating 
horizon (day ahead and pre-schedule) and their planning horizon (beyond 
the operating horizon). Second, we propose that transmission providers 
provide a process flow diagram that illustrates the various steps 
through which the ATC/AFC is calculated.
    173. In addition, we propose to require transmission providers to 
include in Attachment C a detailed explanation of how each of the ATC 
components is calculated for both the operating and planning horizons. 
Thus, for TTC, a transmission provider should: (1) Explain its 
definition of TTC; (2) explain its TTC calculation methodology (e.g., 
load flow, short circuit, stability, transfer studies); (3) list the 
databases used in its TTC assessments; and (4) explain the assumptions 
used in its TTC assessments regarding load levels, generation dispatch, 
and modeling of planned and contingency outages.

[[Page 32662]]

    174. For ETC, we propose to require a transmission provider to 
explain: (1) Its definition of ETC; (2) the calculation methodology 
used to determine the transmission capacity to be set aside for native 
load and non-OATT customers; (3) how point-to-point service requests 
are incorporated; (4) how rollover rights are accounted for; and (5) 
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-time calculations). With regard to (5), we 
seek comment on whether transmission providers currently are keeping 
track of when firm service reservations are not scheduled and should be 
released as non-firm.
    175. If a transmission provider uses an AFC methodology to 
calculate ATC, we propose to require it to explain: (1) Its definition 
of AFC; (2) its AFC calculation methodology (e.g., load flow, short 
circuit, stability, transfer studies); (3) its process for converting 
AFC into ATC; (4) what databases are used in its AFC assessments; (5) 
the assumptions used in its AFC assessments; and (6) the reliability 
criteria used for contingency outages simulation.
    176. For TRM, we propose to require a transmission provider to 
explain: (1) Its definition of TRM; (2) its TRM calculation methodology 
(e.g., its assumptions on load forecast errors, forecast errors in 
system topology or distribution factors and loop flow sources); (3) the 
databases used in its TRM assessments; (4) the conditions under which 
the transmission provider uses TRM; and (5) the process used to prevent 
double-counting of contingency outages used in its TTC and TRM 
calculations. We propose to require transmission providers that do not 
reserve TRM to reflect that in Attachment C. We seek comment on the 
above proposal, specifically on what type of showing a transmission 
provider could make with regard to the process used to prevent double-
counting.
    177. Furthermore, in the CBM Order, the Commission required 
transmission providers to post a specific and self-contained narrative 
explanation of their CBM practices, including who performs the 
assessment (transmission or merchant staff), the methodology used to 
perform generation reliability assessments (e.g., probabilistic or 
deterministic), whether the assessment method reflects a specific 
regional practice, the assumptions used in those assessments and the 
basis for the selection of paths on which CBM is set aside. In 
addition, the Commission directed transmission providers to post their 
procedures for allowing 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). The Commission further stated 
that if a utility's practice was not to reserve CBM, it should reflect 
that in Attachment C. We propose to require transmission providers to 
include this narrative in Attachment C of their OATTs.
    178. In addition, for CBM, we propose to require a transmission 
provider to: (1) Explain its definition of CBM; (2) list the databases 
used in its CBM calculations; and (3) prove that there is no double-
counting of contingency outages when performing CBM calculations.
    179. Though we are proposing to require transmission providers to 
provide greater clarity in the description of their ATC calculations, 
it is our expectation that the reforms we propose for greater 
consistency of ATC methods will minimize the burden on transmission 
providers and customers of assessing various ATC calculation 
methodologies. Ultimately, when the ATC standards development process 
we propose is completed, we expect that Attachment C will refer to the 
NERC standards and will differ by transmission provider only with 
respect to the limited elements of the ATC calculation that may not 
have been made consistent.
OASIS
    180. The Commission's existing regulations require certain ATC-
related information to be posted on each transmission provider's OASIS, 
while other information is required to be provided on request. To 
ensure that relevant information is available on a timely basis to all 
market participants, we propose to amend our regulations to allow 
potential customers greater access to information that will enable them 
to obtain service on a non-discriminatory basis from any transmission 
provider.\173\ We believe that our proposed reforms will not only 
enhance the amount and accuracy of information available to customers, 
but will also increase the ability of the Commission and others to 
detect any potentially unduly discriminatory behavior in a transmission 
provider's calculation and allocation of ATC.
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    \173\ See 18 CFR 37.2 (2005).
---------------------------------------------------------------------------

    181. Our regulations state that a transmission provider's \174\ ATC 
and TTC calculations shall be performed according to consistently 
applied methodologies referenced in the transmission provider's OATT 
and shall be based on current industry practices, standards and 
criteria.\175\ We propose to revise this provision to include 
compliance with the reliability standards developed by the ERO--i.e., 
ATC and TTC calculations shall be performed according to consistently 
applied methodologies referenced in the transmission provider's OATT 
and shall be based on the ERO reliability standards as well as current 
industry practices, standards and criteria.
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    \174\ We note that various provisions of the OASIS regulations 
use the term ``Responsible Party,'' which means the transmission 
provider or an agent to whom the transmission provider has delegated 
the responsibility of meeting any of the requirements of the 
regulations. For simplicity, however, we will use the term 
``transmission provider'' here.
    \175\ See 18 CFR 37.6(b)(2)(i) (2005).
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    182. The regulations further state that, on request, a transmission 
provider must provide all data used to calculate ATC and TTC for any 
constrained paths.\176\ Transmission providers also are required to 
make any system planning studies or specific network impact studies 
performed for customers to determine network impacts publicly available 
on request and to post a list of such studies on the OASIS.\177\ The 
Commission proposes to maintain these requirements.
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    \176\ See 18 CFR 37.6(b)(2)(ii) (2005).
    \177\ See 18 CFR 37.6(b)(2)(iii) (2005).
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    183. The Commission's OASIS regulations require transmission 
providers to calculate and post ATC and TTC for each posted path.\178\ 
The regulations define two classes of posted paths based on usage: 
``constrained'' and ``unconstrained.'' A constrained posted path is any 
posted path for which ATC has been less than or equal to 25 percent of 
TTC at any time during the preceding 168 hours or is calculated to be 
less than, or equal to, 25 percent of TTC for any period during the 
current hour or the next 7 days. An unconstrained posted path is any 
posted path that is not a constrained posted path.\179\ The Commission 
proposes to amend the regulations relating to the data posted for 
constrained posted paths, but largely to retain the existing

[[Page 32663]]

posting requirements for unconstrained posted paths, as set forth 
below.
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    \178\ See 18 CFR 37.6 (2005).
    \179\ See 18 CFR 37.6(b)(1)(iii) (2005). Our regulations require 
transmission providers to post ATC and TTC for specific time 
horizons for constrained posted paths and unconstrained posted 
paths. The Commission proposes to maintain the existing time 
horizons. See 18 CFR 37.6(b)(3)(i)-(ii) (2005).
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    184. First, in the CBM Order, the Commission required transmission 
providers, with respect to each path for which the utility already 
posts ATC, to post (and update) the CBM figure for that path. The 
Commission also required transmission providers to make any transfer 
capability set aside for CBM available on a non-firm basis and to post 
this availability on OASIS. The Commission proposes to incorporate 
these CBM posting requirements into its regulations.
    185. With respect to paths for which the utility already posts ATC, 
TTC, and CBM, we further propose to require each transmission provider 
to also post (and update) the TRM value for that path.
    186. Our existing regulations require ATC and TTC on constrained 
paths to be updated when: (1) Transactions are reserved, (2) service 
ends, or (3) whenever the TTC estimate for the path changes by more 
than 10 percent. We do not believe that this regulation has resulted in 
sufficient information to determine why ATC values changed. To provide 
a transmission customer with useful information to assist with its 
evaluation of monthly and yearly firm transmission service options, we 
propose to supplement the existing regulations by requiring the 
transmission provider to post a brief, but specific, narrative 
explanation of the reason for the posted change in the monthly and 
yearly ATC values on a constrained path. This narrative would describe, 
for example: (1) Scheduling of planned outages and occurrence of forced 
transmission outages; (2) de-ratings of transmission facilities; (3) 
scheduling of planned generation outages and occurrence of forced 
generation outages; (4) changes in load forecast, (5) changes in new 
facilities in-service dates, or other events or assumption changes that 
cause the ATC value to change. We seek comment on whether the posting 
of this new information would provide adequate transparency to the 
customer on a frequent enough basis without imposing an undue burden on 
the transmission provider. We seek comment on whether a similar 
narrative also should be required when ATC remains unchanged at a value 
of zero for some specified period of time.
    187. We propose to maintain the requirement in 18 CFR Sec.  
37.6(e)(2)(i) that a transmission provider must post the reason for a 
denial of a request for service. We propose, however, to amend this 
provision to require a transmission provider to maintain and make 
available information supporting the reason for the denial for five 
years. In addition, we propose to extend the time period for which 
transmission providers must maintain transmission service information 
for audit. Our regulations currently require audit data to be retained 
and made available upon request for download for three years from the 
date when they are first posted.\180\ We propose to change the period 
from three to five years.
---------------------------------------------------------------------------

    \180\ See 18 CFR 37.7(b) (2005).
---------------------------------------------------------------------------

    188. In the CBM Order, the Commission stated that the level of ATC 
set aside for CBM can and should be reevaluated periodically to take 
into account more certain information (such as assumptions that may not 
have, in fact, materialized). Thus, the Commission directed 
transmission providers to periodically reevaluate their generation 
reliability needs so as to make known the availability of CBM and to 
post on OASIS their practices in this regard. We propose to incorporate 
these requirements in the Commission's regulations and to obligate 
transmission providers to reevaluate the CBM set aside at least 
quarterly.
    189. We also propose to require the transmission provider and 
network customers to use the transmission provider's OASIS to request 
designation of a new network resource and to terminate the designation 
of a network resource. As with other transmission request information 
posted on OASIS, the transmission provider should keep designation and 
termination information posted on OASIS for 90 days and should make 
designation and termination information available upon request for five 
years, consistent with 18 CFR 37.7(b) (2005). Transmission customers 
will be able to query requests to designate and terminate a network 
resource under 18 CFR 37.6(a)(6)(2005). We propose to require the 
transmission provider to post on its OASIS a list of its current 
designated network resources and all network customers' current 
designated network resources. The list of network resources should 
include the name of the resource, its geographic and electrical 
location, and the amount of capacity from the unit to be designated as 
a network resource.
    190. Finally, we remind transmission providers that transfer 
capability associated with transmission reservations that are not 
scheduled in real time must be included in non-firm ATC and posted on 
OASIS.\181\
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    \181\ Our regulations require non-firm ATC and TTC for 
constrained posted paths to be posted in the same manner as firm ATC 
and TTC, except that monthly and seasonal capability need only be 
posted if requested. See 18 CFR 37.6(b)(3)(i)(B)(2005).
---------------------------------------------------------------------------

CEII
    191. Shortly after the attacks on September 11, 2001, the 
Commission removed from public viewing certain documents that were 
likely to contain detailed specifications of critical infrastructure 
facilities. CEII is information concerning proposed or existing 
critical infrastructure (physical or virtual) that: (1) Relates to the 
production, generation, transportation, transmission, or distribution 
of energy; (2) could be useful to a person in planning an attack on 
critical infrastructure; (3) is exempt from mandatory disclosure under 
the Freedom of Information Act, 5 U.S.C. 552 (2000); and (4) does not 
simply give the location of the critical infrastructure. Accordingly, 
access to transmission-related information collected by the Commission 
has been restricted by the Commission's CEII regulations. Thus, for 
example, information filed in FERC Form No. 715 (including base case 
power flow data and transmission system maps) as well as system 
planning and network impact studies and models are no longer publicly 
available. However, requesters with a particular need (such as 
transmission customers and consultants with legitimate needs) have the 
opportunity to access information designated as CEII from the 
Commission by submitting a request to the Commission under the 
procedures set forth in our regulations. In Order No. 643,\182\ the 
Commission addressed situations in which its regulations require public 
utilities to disclose information directly to the public. The 
Commission ruled that potential CEII disclosed directly from the public 
utility to the public should be evaluated under the same rules 
addressing the disclosure of CEII from the Commission to the public, 
i.e., if an entity concludes that certain of its information is CEII, 
it must designate it as such and provide other specified information 
about obtaining access to the CEII through the Commission's process. 
The Commission also held that it did not intend to restrict an entity's 
ability to reach appropriate arrangements for sharing CEII, and that 
all persons with a legitimate need for CEII should be able to gain 
access to it with a minimum of difficulty.\183\
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    \182\ Amendments to Conform Regulations with Order No. 630, 
Order No. 643, 68 FR 52089 (Sep. 2, 2003), FERC Stats. & Regs. ] 
31,149 (2003).
    \183\ Id. at P 16.
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    192. We believe that much of the information we propose to require 
transmission providers to provide in this proposed rulemaking will not 
pose CEII concerns. If commenters believe

[[Page 32664]]

that any of the information is CEII, they should explain the basis for 
that view. We recognize that requiring interested persons to use the 
existing CEII process to access information we propose to require 
transmission providers to provide in this rulemaking could undermine 
our goal of providing increased transparency to information necessary 
to evaluate the use of the transmission system. As a result, we seek 
comment on procedures that could be adopted by transmission providers 
to streamline the resolution of CEII concerns and allow timely 
disclosure of information from the transmission providers to interested 
persons.
Additional Data Posting
    193. Notwithstanding our proposed reforms requiring greater 
consistency of and increased transparency into ATC calculation 
methodologies, certain aspects of ATC calculation may remain committed 
to the discretion of the transmission provider. Thus, we believe that 
additional reporting requirements may be necessary to detect undue 
discrimination. Accordingly, we propose to add a requirement in our 
regulations for transmission providers to post on OASIS certain metrics 
related to the provision of transmission service under the pro forma 
OATT. Specifically, we propose to require transmission providers to 
post data each month concerning transmission service requests 
associated with particular paths or flowgates that would clearly 
identify the number of requests that have been accepted and the number 
of requests that have been denied during the prior month. The posted 
data would show: (1) The number of non-affiliate requests for 
transmission service that have been rejected and (2) the total number 
of non-affiliate requests for transmission service that have been made. 
This posting would 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). We also propose that the transmission 
provider post similar information for affiliate transactions. In other 
words, the transmission provider would also post: (1) The number of 
affiliate requests for transmission service that have been rejected, 
and (2) the total number of affiliate requests for transmission service 
that have been made. Similarly, this posting would 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).
    194. Another area of discretion is the load forecasts used by the 
transmission provider when computing ATC. The Commission recognizes 
that the lack of transparency regarding transmission providers' 
forecasted and actual use of the transmission system makes it difficult 
to determine whether an appropriate amount of capacity is being set 
aside for service to native load. To address this concern, we are 
considering additional posting requirements. For example, should 
transmission providers make available their underlying load forecast 
assumptions for all ATC calculations? In addition, should transmission 
providers post, on a daily basis, their actual daily peak load for the 
prior day? We believe that this posting of forecasted and actual loads 
would allow the Commission and others to make a meaningful comparison 
of these elements. We invite comment on whether this information would 
be helpful for such a comparison. We also seek comment on the overall 
benefits of posting metrics and on potential alternative metrics.
    195. For all of our proposed OASIS reforms, we propose to require 
public utilities, working through NAESB, to develop standards for 
consistent methods of posting the new requirements on OASIS so that a 
common format is used.

B. Transmission Planning--Coordinated, Open and Transparent Planning

    196. Order No. 888 set forth certain minimum requirements for 
transmission system planning. For example, the pro forma OATT requires 
transmission providers to plan for the transmission needs of their 
network customers on a comparable basis (section 28.2), and it requires 
them to expand their systems to accommodate firm point-to-point 
customer requests (sections 13.5 and 15.4) that cannot be satisfied due 
to transmission constraints or satisfied more economically via 
redispatch. In addition, in Order No. 888-A, the Commission encouraged 
utilities to engage in joint planning with other utilities and 
customers and to allow affected customers to participate in facilities 
studies to the extent practicable. The Commission also encouraged 
regional planning so that the needs of all participants are represented 
in the planning process.\184\ However, the Commission did not require 
joint planning between transmission providers and their customers or 
between transmission providers in a given region,\185\ nor did it 
impose any specific requirements regarding the manner in which 
transmission providers should coordinate their transmission system 
planning with their pro forma OATT customers. The only section of the 
pro forma OATT that directly speaks to joint planning is section 30.9, 
which provides that for facilities constructed by a network customer, 
the network customer must receive credit where such facilities are 
jointly planned and installed in coordination with the transmission 
provider.\186 \
---------------------------------------------------------------------------

    \184\ See Order No. 888-A at 30,311.
    \185\ See id.
    \186\ Pro forma OATT section 21.2, ``Coordination of Third-Party 
System Additions,'' provides for certain rights for transmission 
providers to coordinate construction of facilities on their systems 
associated with point-to-point customer requests and related 
construction on a third-party transmission system, but imposes no 
obligation on transmission providers.
---------------------------------------------------------------------------

    197. In the NOI, the Commission asked several questions about joint 
planning between transmission providers and their customers. For 
example, we asked whether joint planning should be made mandatory, 
particularly when transmission requests affect adjacent transmission 
systems. We also inquired whether joint planning should be subject to 
an annual reporting requirement or audits. Additionally, we asked for 
comment on a number of issues designed to determine whether any pro 
forma OATT reforms are necessary to ensure that the transmission system 
is expanded so that customers have adequate transmission service. As 
the comments below indicate, commenters generally all believe that 
joint and regional planning are necessary and desirable, but there is a 
split over whether it should continue to be voluntary or should be made 
a requirement.
Comments Supportive of Mandatory Joint and Regional Planning
    198. A number of commenters contend that joint planning between 
transmission providers and their customers should be required by the 
pro forma OATT. Most of these commenters also advocate joint planning 
among transmission providers in a given region. In perhaps the 
strongest comments on the topic, TDU Systems and TAPS request that the 
Commission mandate an open, regional transmission expansion planning 
process that provides opportunities for transmission customers to join 
and participate in the planning process. Many other commenters also 
support joint and regional planning in some form or

[[Page 32665]]

another, with some focusing particularly on requiring such planning 
when adjacent transmission systems are affected.\187\ Bonneville and 
Williams also assert that there is already Commission precedent for 
joint planning in our procedures on large generator interconnections, 
which require the coordination of studies when interconnection requests 
affect other systems. EPSA states that the Commission should require 
that neighboring systems formalize the process under which broad 
regional models are developed and used to study requests on any system 
within a broadly defined region. Powerex points out that the lack of 
regional transmission planning is one of the most difficult issues 
faced in the Pacific Northwest, and PPL asserts that transmission 
planning and expansion in the Western Interconnection does not support 
a competitive market.
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    \187\ E.g., AEP, Alcoa, APPA, Bonneville, Calpine, EPSA, 
Lafayette, National Grid, NCPA, NRECA, Old Dominion, Trans-Elect, 
Williams, and Xcel. Though it does not generally support mandatory 
joint and regional planning, EEI recommends that the Commission 
modify the pro forma OATT to address planning when transmission 
requests require upgrades on or otherwise adversely affect adjacent 
transmission systems.
---------------------------------------------------------------------------

    199. In addition, many commenters contend that transmission 
providers should be required to report on an annual basis the joint and 
regional planning that has occurred or been requested.\188\ TAPS states 
that an annual filing notice by the Commission that gives the public an 
opportunity to comment should be buttressed with audits, in order to 
ensure that transmission providers are taking joint planning with their 
network customers (and neighboring systems) seriously. EPSA likewise 
contends that transmission providers should be required to report to 
the Commission on an annual basis the joint planning that has occurred 
or been requested on their systems, and that the Commission should 
conduct audits to determine the level of compliance with any joint 
planning requirement or agreement.
---------------------------------------------------------------------------

    \188\ E.g., East Texas Cooperatives, EPSA, FMPA, MidAmerican, 
and TAPS.
---------------------------------------------------------------------------

    200. The commenters that advocate mandatory joint and regional 
planning assert that it is needed because transmission providers unduly 
discriminate against their customers when planning their transmission 
systems. For example, a number of commenters assert that transmission 
providers meet their own needs for transmission planning and 
construction before (and often without) meeting those of their 
customers.\189\ NRECA asserts that since the implementation of Order 
No. 888, a number of public utility transmission providers--despite 
clearly stated obligations in the pro forma OATT--have not planned for 
their load-serving transmission customers on a basis comparable to that 
of their own bundled retail native load. TDU Systems believes that 
joint and regional transmission planning is a critical component of 
ensuring comparability between a transmission provider's use of the 
transmission system and a network customer's use of the transmission 
system, largely because transmission providers have an incentive to 
thwart the expansion planning process. Both NRECA and TDU Systems argue 
that the planning processes in RTOs and ISOs also are insufficient 
because they often only allow customer input after transmission plans 
are developed by individual transmission providers.
---------------------------------------------------------------------------

    \189\ E.g., FMPA, Midwest Municipals, NCPA, and NRECA.
---------------------------------------------------------------------------

    201. TAPS asserts that the absence of joint planning has resulted 
in unduly discriminatory transmission service. For comparable service 
to be a reality, TAPS asserts that the transmission system must be 
planned and built for customer needs, just as it must be planned and 
built to meet the transmission providers' need to provide service to 
their native loads. Old Dominion contends that transmission providers 
often locate transmission in such a way that it favors their own 
generation. According to Lafayette, transmission providers have 
increased their generation dominance by inadequately planning for the 
needs of their transmission customers so that they are unable to turn 
to alternative suppliers. East Texas Cooperatives also argues that some 
transmission providers continue to plan their systems in isolation from 
the needs of other load-serving entities. EPSA concludes that the 
transmission needs of non-transmission provider customers are simply 
not integrated effectively into the planning process. APPA notes that 
the original goal of the pro forma OATT--an inclusive planning process 
that takes into account on a comparable basis the load growth and new 
generation resource needs of all loads served using the transmission 
provider's system--has not been achieved. Many commenters assert that 
joint and regional transmission planning is necessary in order to 
ensure adequate infrastructure development.\190\ Others focus on the 
need for joint and regional planning to address the fact that changes 
on one system often affect transmission service on adjacent 
systems.\191\ Lastly, APPA blames substantial and rising congestion 
costs on inadequate transmission planning, and EPSA contends that 
better transmission planning is needed to support a competitive 
electricity market.
---------------------------------------------------------------------------

    \190\ E.g., AEP, Calpine, Constellation, East Texas 
Cooperatives, ELCON, NRECA, and TransAlta.
    \191\ E.g., Alcoa and EPSA. EEI acknowledges the planning 
difficulties that arise when a transmission request on one system 
causes the need for upgrades to another system.
---------------------------------------------------------------------------

Comments Supportive of Voluntary Joint and Regional Planning
    202. Another large group of commenters, including many investor-
owned utilities, stress that joint and regional planning, while 
laudable, should not be mandatory and that it should continue to be 
voluntary or that processes are already in place to encourage regional 
planning.\192\ Progress Energy, for example, contends that there are 
several formalized processes in place today that foster joint and 
regional planning, such as the process in North Carolina. Southern 
points out that in addition to participating in Southeastern Electric 
Reliability Council (SERC) planning activities, it is engaged in other 
types of joint regional planning (e.g., through the Georgia Integrated 
Transmission System (Georgia ITS)).\193\ Nevada Companies supports the 
approach already used in the WECC, which employs interconnection-wide 
models for planning. Nevada Companies explains that these studies are 
then made available to all other WECC transmission providers. In 
addition, APS, Tacoma, and WAPA point to numerous forums (e.g., the 
Southwest Area Transmission planning group and the Southwest 
Transmission Expansion Plan process) where transmission providers and 
other industry stakeholders coordinate their transmission plans. LPPC 
also states that the Georgia ITS has provided benefits to participants 
and the region--in the form of improved investment in infrastructure 
and through the introduction of new sources of capital.

[[Page 32666]]

Lastly, some commenters point out that collaborative regional planning 
already occurs in RTO and ISO regions.\194\ With regard to PJM, 
however, TDU Systems argues that better transmission planning is 
required due to PJM's ``rubber-stamping'' of transmission provider 
identified transmission upgrades. Exelon states that the Northeastern 
ISO/RTO Planning Coordination Protocol is a formal agreement, executed 
in 2004, among the PJM Interconnection, the New York Independent System 
Operator, and ISO New England, pursuant to which the three 
organizations conduct a comprehensive process of coordinating system 
planning activities.
---------------------------------------------------------------------------

    \192\ E.g., Cinergy, Entergy, KCP&L, LPPC, MidAmerican, Nevada 
Companies, North Carolina Commission, Northwestern, PNM-TNMP, 
Progress Energy, Salt River, Snohomish, South Carolina Regulatory 
Staff, Southern, Tacoma, and WAPA. Nevertheless, KCP&L, Nevada 
Companies, and Progress Energy join with EPSA in calling for a more 
formalized process for addressing base case and expansion plans.
    \193\ Georgia ITS consists of jointly-owned transmission 
facilities, which are owned by the Southern subsidiary Georgia 
Power, the Municipal Electric Authority of Georgia, the Georgia 
Transmission Corporation--a cooperative utility--and Dalton 
Utilities--a municipal system.
    \194\ E.g., Ameren, CAISO, Exelon, ISO New England, and 
MidAmerican.
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    203. With regard to the imposition of reporting requirements, many 
commenters argue that transmission providers already are required to 
report joint planning activities.\195\ EEI, for example, contends that 
joint planning activities under section 30.9 of the pro forma OATT 
currently are required to be reported on each transmission provider's 
OASIS. EEI argues that audits should not be required. Bonneville 
contends that, at least in the Pacific Northwest, annual reporting and 
audits are not needed. Bonneville states that transmission planning 
staffs already bear a heavy workload; for example, Bonneville's 
planning staff must address many requests for transmission and 
interconnection service, as well as conduct regional planning efforts 
and comply with regional and national reliability initiatives. 
Northwestern states that reporting requirements or audits are not 
needed and would be burdensome to the transmission provider, 
distracting it from performing its joint planning responsibilities.
---------------------------------------------------------------------------

    \195\ E.g., Bonneville, EEI, KCP&L, PNM-TNMP, Salt River, 
Tacoma, and WAPA.
---------------------------------------------------------------------------

Current pro forma OATT Planning Responsibilities
    204. Order No. 888 and the pro forma OATT require that transmission 
providers plan and upgrade their transmission systems to provide 
comparable open access transmission service for their transmission 
customers. For example, with regard to network service, section 28.2 of 
the pro forma OATT provides that the transmission provider ``will plan, 
construct, operate and maintain its Transmission System in accordance 
with Good Utility Practice in order to provide the Network Customer 
with Network Integration Transmission Service over the Transmission 
Provider's Transmission System.'' Section 28.2 also provides that the 
Transmission Provider shall, consistent with Good Utility Practice, 
``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.''
    205. The pro forma OATT also requires that new facilities be 
constructed to meet the service requests of long-term firm point-to-
point customers. Section 13.5 of the pro forma OATT requires the 
transmission provider to consider redispatch of the system to relieve 
any constraints that are inhibiting a transmission customer's point-to-
point service if it is economical to do so; but if redispatch is not 
economical, the transmission provider is obligated to expand or upgrade 
its system. This expansion obligation on the part of the transmission 
provider for point-to-point service is found in section 15.4 of the pro 
forma OATT, which provides that when a transmission provider cannot 
accommodate a point-to-point transaction because of insufficient 
capability on its system, it will ``use due diligence to expand or 
modify its Transmission System to provide the requested Firm 
Transmission Service.'' Section 15.4 goes on to provide that ``the 
Transmission Provider will conform to Good Utility Practice in 
determining the need for new facilities and in the design and 
construction of such facilities.'' Importantly, however, the 
transmission provider's obligation to upgrade or expand its system to 
provide point-to-point service as detailed in section 15.4 is 
contingent on the transmission customer agreeing to compensate the 
transmission provider for such costs pursuant to the terms of section 
27 (providing for cost responsibility for upgrades and/or redispatch 
``to the extent consistent with Commission policy''). Order No. 888 
does not, however, require that transmission providers coordinate with 
either their network or point-to-point customers in transmission 
planning or otherwise publish the criteria, assumptions, or data 
underlying their transmission plans.\196\
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    \196\ Certain transmission data is required to be provided 
annually in the FERC Form 715 (e.g., Part 2--Power Flow Base Cases, 
Part 3--Transmitting Utility Maps and Diagrams, Part 4--Transmission 
Planning Reliability Criteria, Part 5--Transmission Planning 
Assessment Practices, and Part 6--Evaluation of Transmission System 
Performance). As discussed below, we do not believe that the FERC 
Form 715 reporting requirements have satisfied the need for 
transparency with regard to transmission planning.
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The Need for Reform
    206. As discussed more fully in Part III.C above, in the ten years 
since Order No. 888 was issued, the Nation has witnessed a decline in 
transmission investment relative to load growth. As a result, 
transmission capacity per MW of peak demand has declined in every NERC 
region, and it has been estimated that capital spending must increase 
significantly to ensure system reliability and to accommodate wholesale 
electric markets. Many have argued that inadequate expansion of the 
transmission grid has contributed to the widespread transmission 
constraints that plague most regions of the country, as reflected in 
the limited amounts of ATC posted in many regions, increased frequency 
of denied transmission services requests, and increasingly common 
transmission service interruptions or curtailments, all of which make 
it more difficult for transmission customers to transfer power. In 
short, it has become clear that since Order No. 888 was issued, the 
Nation's transmission grid has not been planned and developed 
adequately and projections suggest that without reform this trend will 
continue.
    207. The need for transmission planning reform also has been 
recognized by the Consumer Energy Council of America (CECA), a public 
interest energy policy organization with a 30-year history of bringing 
stakeholders together to find solutions to contentious energy policy 
issues. CECA launched its Transmission Infrastructure Forum in early 
2004,\197\ which published its conclusions in January 2005 in a final 
report titled ``Keeping the Power Flowing: Ensuring a Strong 
Transmission System to Support Consumer Needs for Cost-Effectiveness, 
Security and Reliability'' (CECA Report).\198\ Among other things, the 
CECA Report concludes that regional transmission planning with consumer 
input early in the process is needed to ensure the development of a 
robust transmission system capable of meeting consumer needs reliably 
and at

[[Page 32667]]

reasonable cost over time. The CECA Report stresses that regional 
transmission planning must address inter-regional coordination, the 
need for both reliability and economic upgrades to the system, as well 
as critical infrastructure to support national security and 
environmental concerns.\199\
---------------------------------------------------------------------------

    \197\ The CECA Transmission Infrastructure Forum included 
representatives from such diverse constituencies as investor-owned 
utilities, rural electric cooperatives, municipal power systems, 
federal power systems, independent power producers, equipment 
manufacturers, the U.S. Congress, the Commission, the U.S. 
Department of Energy, state legislatures, state public utility 
commissions, state energy offices and consumer advocates, consumer 
and environmental organizations, independent consultants, and 
academic institutions.
    \198\ Available at http://www.cecarf.org/Publications/PublicationsAllDate.html
.

    \199\ See, e.g., CECA Report at 10-11.
---------------------------------------------------------------------------

    208. Transmission providers have a disincentive to remedy 
transmission congestion when doing so reduces the value of their 
generation or otherwise stimulates new entry or greater competition in 
their area. As the Commission noted in Order No. 888, ``[i]t is in the 
economic self-interest of transmission monopolists, particularly those 
with high-cost generation assets, to deny transmission or to offer 
transmission on a basis that is inferior to that which they provide 
themselves.'' \200\ This statement continues to be true today. In 
upholding the Commission's authority to require open access in Order 
No. 888, the court in TAPS v. FERC noted that ``[u]tilities that own or 
control transmission facilities naturally wish to maximize profit. The 
transmission-owning utilities thus can be expected to act in their own 
interest to maintain their monopoly and to use that position to retain 
or expand the market share for their own generated electricity, even if 
they do so at the expense of lower-cost generation companies and 
consumers.'' \201\ Thus, even when transmission providers do address 
congestion, they have an incentive to do so in a manner that benefits 
their own generation or loads rather than the generation or loads of 
their competitors. These disincentives frustrate new investment that 
could remedy both ``local'' congestion (i.e., within the transmission 
provider's control area) and congestion between control areas, as well 
as remedy undue discrimination and increase bulk power trade. For 
example, a transmission provider does not have an incentive to relieve 
local congestion that restricts the output of a competing merchant 
generator if doing so will make the transmission provider's own 
generation less competitive. A transmission provider also does not have 
an incentive to increase the import or export capacity of its 
transmission system if doing so would allow cheaper power to displace 
its higher cost generation or otherwise make new entry more profitable 
by facilitating exports.
---------------------------------------------------------------------------

    \200\ Order No. 888 at 31,682.
    \201\ 225 F.3d at 684; see also New York v. FERC, 535 U.S. at 8-
9 (addressing Order No. 888's open access requirements, the Court 
noted that ``public utilities retain ownership of the transmission 
lines that must be used by their competitors to deliver electric 
energy to wholesale and retail customers. The utilities' control of 
transmission facilities gives them the power either to refuse to 
deliver energy produced by competitors or to deliver competitors' 
power on terms and conditions less favorable than those they apply 
to their own transmissions.'') (citation and footnote omitted).
---------------------------------------------------------------------------

    209. The existing pro forma OATT does not adequately address the 
above-referenced problems. As noted, there is no general requirement 
that a transmission provider coordinate its transmission planning with 
customers, market participants, or its interconnected neighbors.\202\ 
Additionally, though the pro forma OATT does require transmission 
providers to plan for the needs of their network customers and to 
expand their systems to provide service to point-to-point customers, 
there is no requirement that the overall transmission planning process 
be open to customers, competitors, and state commissions. Rather, the 
transmission provider currently is allowed to create its own 
transmission plan with limited or no input from affected market 
participants or other affected entities, such as state commissions. 
There is also no requirement that the planning process be transparent. 
While we recognize that certain planning information is required to be 
filed annually in FERC Form No. 714--Annual Electric Control and 
Planning Area Report and FERC Form 715--Annual Transmission Planning 
and Evaluation Report, this does not appear to provide sufficient 
transparency to remedy the remaining concerns expressed in this 
proceeding about the potential for undue discrimination in planning.
---------------------------------------------------------------------------

    \202\ As discussed more fully in Part V.C.2, section 30.9 of the 
current pro forma OATT may inhibit coordinated planning by making 
transmission providers reluctant to engage in coordinated planning, 
because of the requirement to give customers credits for jointly 
planned facilities. We are proposing to sever the link between 
credits and planning, and treat the two issues separately within the 
pro forma OATT.
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    210. Taken together, this lack of coordination, openness, and 
transparency results in opportunities for undue discrimination in 
transmission planning. Without adequate coordination and open 
participation, market participants have no input into whether a 
particular plan treats all loads and generators comparably. Without 
sufficient transparency, market participants have no means to determine 
whether the plan developed by the transmission provider in isolation is 
discriminatory. Moreover, the process is inefficient. Disputes over 
discrimination occur primarily after-the-fact because there is 
insufficient coordination and transparency between transmission 
providers and their customers for purposes of planning. The Commission 
has a duty to prevent undue discrimination in the rates, terms, and 
conditions of public utility transmission service, and therefore, an 
obligation to remedy these transmission planning deficiencies. The 
Commission's authority to remedy undue discrimination is broad.\203\ In 
addition, new section 217 of the FPA requires the Commission to use its 
FPA authorities in a manner that facilitates the planning and expansion 
of transmission facilities to meet the reasonable needs of load-serving 
entities. Finally, we note that a more transparent and coordinated 
regional planning process can support the DOE's responsibilities under 
EPAct 2005 section 1221 to study transmission congestion and issue 
reports designating National Interest Transmission Corridors.
---------------------------------------------------------------------------

    \203\ See Order No. 888 at 31,669 (noting that the FPA ``fairly 
bristles'' with concern for undue discrimination (citing Associated 
Gas Distributors v. FERC, 824 F.2d 981, 998 (D.C. Cir. 1987)).
---------------------------------------------------------------------------

    211. We are encouraged that since the adoption of open access in 
Order No. 888, a number of voluntary coordinated and regional planning 
efforts have been developed throughout the country, including those 
administered by RTOs and ISOs. For example, each of the Commission-
approved RTOs in the Northeast, Midwest and Southwest, as well as 
CAISO, provide for a coordinated and regional planning process with 
stakeholder input from each industry segment. The Commission also notes 
that there are several other promising efforts to establish voluntary 
coordinated and regional planning efforts around the country. For 
example, WECC is in the process of expanding its reliability 
responsibilities to include comprehensive transmission planning to 
address the regional economic transmission needs of its members and 
other stakeholders in its regional footprint. In addition, each of the 
subregions in WECC has a coordinated transmission planning process 
that, in varying degrees, is open to market participants and, in some 
instances, has resulted in significant new transmission being built on 
a joint ownership basis. In North Carolina, Duke, Progress Energy, and 
two other organizations--North Carolina Electric Membership Corporation 
and ElectriCities of North Carolina, Inc.--have endeavored to create 
and implement a collaborative electric transmission planning process in 
that state. This process provides for broad stakeholder input as well 
an independent facilitator. Other models

[[Page 32668]]

for coordinated planning include the Georgia ITS and joint ownership 
arrangements like it around the country.
    212. We fully support these voluntary efforts and believe they are 
consistent in significant respects with the nature of the reforms we 
are proposing for transmission planning under the pro forma OATT. In 
those regions and subregions that already have adopted significant 
reforms, our proposal may require only modest changes, while other 
regions and subregions may need to undertake more significant changes 
to the way in which the transmission system is planned today.
    213. Today, numerous competing interests have a need to utilize the 
transmission grid, and yet in many areas of the country that grid is 
planned much the same way as it was before the electric industry 
matured into a regional business and Order No. 888 was implemented. 
That is, the same public utilities that own and control the grid also 
control the planning process that governs when and how the grid is 
expanded and upgraded. In short, the transmission grid is being 
utilized in a fundamentally different way, consistent with the intent 
of open access, and a decade of experience has shown us that in order 
to remedy undue discrimination, the existing provisions of the pro 
forma OATT respecting transmission system planning must be reformed. 
Accordingly, in order to provide for more comparable open access 
transmission service, eliminate the potential for undue discrimination 
and anticompetitive conduct, and satisfy our statutory responsibilities 
under section 217 of the FPA, we propose that each public utility 
transmission provider participate in an open and transparent local and 
regional planning process that addresses certain fundamental principles 
of transmission planning. As we indicated above, existing regional 
planning processes will be expected to meet or exceed the transmission 
planning principles we outline in this proposed rule.
Coordinated, Open, and Transparent Transmission Planning
    214. In order to eliminate the potential for undue discrimination 
as described above, and to ensure that comparable transmission service 
is provided by all public utility transmission providers, including 
RTOs and ISOs, we propose to amend the pro forma OATT to require 
coordinated, open, and transparent transmission planning on both a 
local and regional level. We propose to require each public utility 
transmission provider to submit, as part of its compliance filing in 
this proceeding, a proposal for a coordinated and regional planning 
process that complies with the following coordinated and regional 
planning principles.\204\ In the alternative, transmission providers 
may make a compliance filing in this proceeding describing their 
existing coordinated and regional planning process and showing that it 
is consistent with or superior to the requirements set forth below. 
Moreover, we expect municipal, cooperative, and other public power 
entities to participate in these processes as well, consistent with 
their obligation to provide reciprocal transmission service as detailed 
in Order No. 888. An open and transparent regional planning process 
cannot succeed unless all transmission owners participate.
---------------------------------------------------------------------------

    \204\ The revised pro forma OATT reflects the proposed planning 
requirement in sections 15.4, 16.1, 17.2(x), 28.2, 29.2, 31.6, and 
Attachment K.
---------------------------------------------------------------------------

    Under our proposal in this NOPR, a coordinated, open and 
transparent process must satisfy the following eight principles:
    1. Coordination--The transmission provider must meet with all its 
transmission customers and interconnected neighbors to develop a 
transmission plan on a nondiscriminatory basis. The Commission seeks 
comment on specific requirements for this coordination, such as the 
minimum number of meetings to be required each year, the scope of the 
meetings, the notice requirements, the format, and any other features 
deemed important by commenters.
    2. Openness--Transmission planning meetings must be open to all 
affected parties (including all transmission and interconnection 
customers, and state commissions). The Commission seeks comment on 
whether there are any circumstances under which participation should be 
limited, e.g., to address confidentiality concerns.
    3. Transparency--The transmission provider is required to disclose 
to all customers and other stakeholders the basic criteria, 
assumptions, and data that underlie its transmission system plans. The 
Commission seeks comment on whether the information provided in FERC 
Form 715 is adequate and, if not, what additional detail should be 
provided. The Commission also seeks comment on the format for 
disclosure, including protections to address confidentiality concerns.
    4. Information Exchange--Network transmission customers are 
required to submit information on their projected loads and resources 
on a comparable basis (e.g., planning horizon and format) as used by 
transmission providers in planning for their native load; and point-to-
point customers are required to submit any projections they have of a 
need for service over the planning horizon and at what receipt and 
delivery points. The Commission seeks comment on whether specific 
requirements should be adopted for this information exchange.\205\ The 
transmission provider must allow market participants the opportunity to 
review and comment on draft transmission plans.
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    \205\ For network service, some of this information already is 
required by sections 29, 30 and 31 of the pro forma OATT, but to the 
extent it is not, we propose to require customers to provide 
additional information as necessary for the transmission provider to 
develop a system plan.
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    5. Comparability--After considering the data and comments supplied 
by market participants, the transmission provider is to develop 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.
    6. Dispute Resolution--The transmission provider must propose a 
dispute resolution process, such as requiring senior executives to meet 
prior to the filing of any complaint and using a third-party neutral. 
The Commission's Dispute Resolution Service is available to assist 
transmission providers in developing a dispute resolution process. In 
addition to informal dispute resolution, affected parties would have 
the right to file complaints with the Commission under FPA section 206. 
The Commission seeks comment on whether any specific dispute resolution 
processes should be required.
    7. Regional Participation--In addition to preparing a system plan 
for its own control area on an open and nondiscriminatory basis, the 
transmission provider is required to 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 
``significant and recurring'' transmission congestion (defined below). 
The Commission strongly encourages that such coordination encompass as 
broad a region as possible, given the interconnected nature of the 
transmission grid and the efficiency of addressing these issues in a 
single forum. The Commission also recognizes that, as in the West, it 
may be appropriate to organize regional planning efforts on both a 
subregional

[[Page 32669]]

and regional level. The Commission seeks comment on whether there are 
existing institutions (such as the NERC regional councils or 
subregional planning groups) that are well situated to perform or 
coordinate this function.
    8. Congestion Studies--The transmission provider is required 
annually to prepare studies identifying ``significant and recurring'' 
congestion and post such studies on its OASIS. The studies should 
analyze and report on the location and magnitude of the congestion; 
possible remedies for the elimination of the congestion, in whole or in 
part; the associated costs of congestion; and the cost associated with 
relieving congestion through system enhancements (or other means). The 
Commission seeks comment on how to define ``significant and recurring'' 
congestion, such as by reference to generation redispatch, repeated 
denials of service requests, zero ATC, frequent curtailments or a 
combination of these factors. The required congestion studies would 
address both ``local'' congestion (i.e., within the transmission 
provider's system) and congestion between control areas and subregions. 
The purpose of this requirement is to ensure that affected market 
participants, state commissions, and this Commission understand both 
the costs of recurring transmission congestion and the remedies. The 
Commission seeks comment on how this information should be used by the 
transmission provider and market participants to address significant 
and recurring congestion.
    215. The Commission encourages the use of an independent third 
party to oversee or coordinate the planning process. The Commission is 
not proposing to require an independent third party to control the 
process, but does believe that independence can provide greater 
confidence in the planning process and resulting studies. Independence 
can take many forms, from having an independent entity resolve disputes 
over planning assumptions and decisions (as in an RTO) to having an 
independent consultant coordinate and otherwise perform the annual 
congestion studies referred to above. The Commission seeks comment on 
the levels of independence that can provide benefits and the 
institutions that could offer such independence, such as whether 
Regional Entities under the ERO could provide such independence.
    216. Additionally, the Commission strongly encourages the 
participation of state commissions and other state agencies, 
particularly with regard to regional planning, in the coordinated 
transmission planning processes being proposed in this NOPR. The 
participation and support of state commissions and other state agencies 
is important because state commissions regulate the cost of 
transmission that is included in bundled retail rates and states also 
perform transmission siting. Many states also have traditionally been 
involved in utility planning in some way for their state or region. The 
Commission seeks comment on how best to accommodate effective state 
participation.
    217. The Commission seeks comment on several aspects of this 
proposal. First, the Commission seeks comment on how much flexibility 
each transmission provider in a region should be given in implementing 
any principles adopted. Second, the Commission seeks comment, by way of 
examples, on transmission planning processes that comply with the 
proposed transmission planning reforms in principle.
    218. Third, we seek comment on whether there are other principles 
or requirements that should be adopted to support the construction of 
needed new infrastructure and otherwise ensure that all market 
participants are treated on a comparable basis. For example:
    a. We seek comment on whether there should be a principle or 
guideline to govern the recovery and allocation of costs associated 
with funding the regional planning requirement. To devote the resources 
necessary to support an open and transparent regional planning process, 
we recognize that the participating entities must be assured of 
recovery of their costs, as well as assured that the costs will be 
borne equitably by all parties benefiting from the process.
    b. We seek comment on whether there should be a requirement that, 
at least for large new transmission projects (such as new regional 
backbone facilities), there be an open season to allow market 
participants to participate in joint ownership of these projects. We 
believe that such a requirement could stimulate more investment in the 
grid and ensure that all customers have the ability to participate in 
new projects on a nondiscriminatory basis, including smaller market 
participants that cannot support the construction of large new 
facilities on their own.\206\ We seek comment on whether to include 
such a requirement and, if so, what conditions or limitations should be 
associated with it.
---------------------------------------------------------------------------

    \206\ We note that transmission providers in the Western 
Interconnection already participate in regional and sub-regional 
transmission planning processes that include the opportunity for 
joint financing and ownership of transmission facilities. Such 
facilities are typically owned by the participants as ``tenants in 
common'' with each participant owning a pro rata share of the land 
and common facilities and sharing the costs and expenses in 
proportion to their ownership percentage in each project. 
Additionally, all owners participate in the oversight and 
administration of jointly-owned projects through representation on 
various administration committees. Among other benefits, this has 
allowed all participating utilities, large and small, to take 
advantage of the economies of scale associated with larger 
transmission projects.
---------------------------------------------------------------------------

    c. We further seek comment on whether there should be a specific 
study process to identify opportunities to enhance the grid for 
purposes beyond maintaining reliability or reducing current congestion. 
Such a process would allow interested entities, including state 
resource agencies, siting bodies and commissions, load-serving 
entities, or other market participants to request that the transmission 
provider model grid upgrades needed to accommodate the construction of 
new resources, e.g., remote coal, nuclear or wind on a local and 
regional basis and prior to the existence of an actual proposal for 
such resources. Such a process could provide the information necessary 
to allow interested entities to proactively evaluate, on a 
nondiscriminatory basis, different resource options in light of the 
differing transmission infrastructure needs associated with them. We 
recognize that resource planning is traditionally performed at the 
state level and do not believe that any such study process would 
conflict with these state prerogatives. To the contrary, we believe 
such a study process could provide states better information to 
evaluate all relevant resource options in exercising their resource 
adequacy authority.
    d. We also seek comment on whether we should require public 
utilities to develop cost allocation principles to address the sharing 
of the costs of new transmission projects. Would the development of 
specific cost allocation principles provide greater certainty and hence 
support the construction of new infrastructure? Or is cost allocation 
better handled on a case-by-case basis? We also seek comment on how, as 
part of any cost allocation process, to address the fact that upgrades 
that may not be needed for reliability in the near term (e.g., 3-5 
years) may be necessary to support reliability in the longer term 
(e.g., 10-15 years). Furthermore, because transmission upgrades, 
particularly multi-state regional backbone facilities, often can 
require 10 to 15 years to construct, we seek comment on whether the 
planning process proposed here should be

[[Page 32670]]

required to look out at least as far as the longest time it would take 
to build such an upgrade in the region in question.
    219. Finally, the Commission seeks comment on the level of detail 
to be required in transmission providers' OATTs.

C. Transmission Pricing

    220. Order No. 888 and the pro forma OATT included primarily non-
rate terms and conditions of open access non-discriminatory 
transmission service. The Commission required transmission providers to 
propose corresponding rates in a subsequent filing under FPA section 
205. Similarly, here we do not propose to undertake a comprehensive 
overhaul of our transmission pricing policies. We do, however, propose 
a number of reforms to several discrete provisions in the pro forma 
OATT, as further described below. We also provide a clarification of 
our policy for pricing of system expansions.
1. Imbalances
Energy Imbalances
    221. In Order No. 888, the Commission concluded that six ancillary 
services must be included in an OATT.\207\ One of those ancillary 
services is energy imbalance service under Schedule 4 of the pro forma 
OATT.\208\ Energy imbalance service is provided when the transmission 
provider makes up for any difference that occurs over a single hour 
between the scheduled and the actual delivery of energy to a load 
located within its control area.\209\ The Commission recognized that 
the amount of energy taken by load in an hour is variable and not 
subject to the control of either a wholesale seller or a wholesale 
requirements buyer.\210\
---------------------------------------------------------------------------

    \207\ Order No. 888 at 31,703.
    \208\ Id.
    \209\ See id. at 31,960.
    \210\ Order No. 888-A at 30,230.
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    222. The Commission found that the energy imbalance service should 
have an energy deviation band appropriate for load variations and a 
price for exceeding the deviation band that is appropriate for 
excessive load variations.\211\ The deviation band established by the 
Commission is an hourly deviation band of 1.5 percent (with 
a minimum of 2 MW) for energy imbalance. The Commission explained that 
this deviation band promotes good scheduling practices by transmission 
customers, which ensures that the implementation of one scheduled 
transaction does not overly burden another.\212\
---------------------------------------------------------------------------

    \211\ Id.
    \212\ Id. at 30,232.
---------------------------------------------------------------------------

    223. With respect to compensation associated with the hourly energy 
deviation band, the Commission explained that for energy imbalances 
within the deviation band, the transmission customer may make up the 
difference within 30 days (or other reasonable period generally 
accepted in the region) by adjusting its energy deliveries to eliminate 
the imbalance (i.e., return energy in kind within 30 days).\213\ In 
addition, the Commission explained that the transmission customer must 
compensate the transmission provider for each imbalance that exceeds 
the hourly deviation band and for accumulated minor imbalances that are 
not made-up within 30 days.\214\ With respect to the price of energy 
imbalance service, the Commission explained that it intentionally did 
not provide detailed pricing requirements.\215\ Instead, the Commission 
required transmission providers to propose rates for energy imbalance 
service.\216\
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    \213\ Id. at 30,229.
    \214\ Id. The Commission further stated that the pro forma OATT 
permits schedule changes up to twenty minutes before the hour at no 
charge, and that it would allow the transmission provider and the 
customer to negotiate and file another deviation band more flexible 
to the customer, if the same deviation band is made available on a 
not unduly discriminatory basis. Id. at 30,232-33.
    \215\ Id. at 30,234.
    \216\ Id.
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    224. Although transmission providers have different energy 
imbalance charges, they typically require customers to correct energy 
imbalances within the deviation band through return in kind or a 
financial settlement that requires payment for underdeliveries of 
energy equal to 100 percent of the transmission provider's system 
incremental cost for the hour the deviation occurred. For energy 
overdeliveries, the transmission customer would receive a payment equal 
to 100 percent of the transmission provider's decremental cost for the 
hour the deviation occurred.\217\ Outside the deviation band, 
transmission providers either charge the transmission customer: (1) A 
percentage of the utility's system cost, such as 110 percent of 
incremental costs for underscheduling or 90 percent of decremental 
costs for overscheduling, or (2) the greater of a percentage of system 
costs or a fixed charge, such as $100 per MWh.\218\
---------------------------------------------------------------------------

    \217\ See, e.g., Arizona Public Service Co., FERC Electric 
Tariff, Twelfth Revised Volume No. 2, Schedule 4 (Energy Imbalance 
Charge), accepted in Arizona Public Service Co., Docket No. ER04-
442-003 (Sep. 30, 2004) (unpublished letter order); Public Service 
Company of New Mexico, FERC Electric Tariff, Second Revised Volume 
No. 4., Schedule 4 (Energy Imbalance Charge), accepted in Public 
Service Co. of New Mexico, Docket No. ER04-416-002 (Sep. 30, 2004) 
(unpublished letter order).
    \218\ See Arizona Electric.; see also Idaho Power Co., 102 FERC 
] 61,351 (2003); see also Duke Electric Transmission FERC Electric 
Tariff, Third Revised Volume 4, Original Sheet No. 120 accepted in 
Duke Energy Corp., Docket No. ER04-812-001 (Jul. 2, 2004) 
(unpublished letter order).
---------------------------------------------------------------------------

Generator Imbalances
    225. While the Commission found in Order No. 888 that energy 
imbalance was an ancillary service, it also recognized that differences 
arise between energy scheduled for delivery from a generator and the 
amount of energy actually generated in an hour,\219\ commonly called 
generator imbalance. It concluded, however, that a generator should be 
able to deliver its scheduled hourly energy with precision and 
expressed concern that if it were to allow the generator to deviate 
from its schedule by 1.5 percent without penalty, so long as it 
returned the energy in kind at another time, it would discourage good 
generator operating practices.\220\ The Commission stated that a 
generator's interconnection agreement with its transmission provider or 
control area operator should specify the requirements for the generator 
to meet its schedule and any consequence for persistent failure to meet 
its schedule.\221\
---------------------------------------------------------------------------

    \219\ Order No. 888-A at 30,230.
    \220\ Id.
    \221\ Id.
---------------------------------------------------------------------------

    226. Subsequently, however, the Commission, in a number of cases, 
accepted modifications to a transmission provider's OATT to include 
generator imbalance provisions.\222\ Moreover, in Order No. 2003-B, the 
Commission permitted the transmission provider to include a provision 
for generator balancing service arrangements in individual 
interconnection agreements.\223\ Further, in a NOPR concerning 
generator imbalance provisions for intermittent resources, the 
Commission proposed to establish a standardized schedule under the pro 
forma OATT to address generator imbalances created by

[[Page 32671]]

intermittent resources and to clarify the application of the current 
energy imbalance provision of the pro forma OATT.\224\ In particular, 
the Commission proposed that generator imbalance provisions for 
intermittent resources would reflect a deviation band of 10 
percent (with a minimum of 2 MW) and allow net hourly intermittent 
generator imbalances within the deviation band to be settled at the 
system incremental cost at the time of the imbalance.\225\ The 
Commission also reiterated its policy that a transmission provider may 
only charge the transmission customer for either hourly generator 
imbalances or hourly energy imbalances for the same imbalance, but not 
both.
---------------------------------------------------------------------------

    \222\ See, e.g., Niagara Mohawk Power Corp., 86 FERC ] 61,009 
(1999) (Niagara Mohawk); PacifiCorp, 95 FERC ] 61,145, order on 
reh'g and clarification, 95 FERC ] 61,467 (2001); Alliant Energy 
Corporate Services, Inc., 93 FERC ] 61,340 (2000); Wolverine Power 
Supply Coop., 93 FERC ] 61,330 (2000); Commonwealth Edison Co., 93 
FERC ] 61,021 (2000); FirstEnergy Operating Cos., 93 FERC ] 1,200 
(2000), order denying reh'g & granting clarification, 94 FERC ] 
61,184 (2001); Tampa Electric Co., 90 FERC ] 61,330 (2000), reh'g 
denied, 95 FERC ] 61,101 (2001); Florida Power Corp., 89 FERC ] 
61,263 (1999); Consumers Energy Co., 87 FERC ] 61,170 (1999).
    \223\ Order No. 2003-B at P 74-75.
    \224\ Imbalance Provisions for Intermittent Resources; Assessing 
the State of Wind Energy in Wholesale Electricity Markets, Notice of 
Proposed Rulemaking, 70 FR 21349 (Apr. 26, 2005), FERC Stats. & 
Regs. ] 32,581 at P 9 (2005) (Imbalance Provisions Proceeding).
    \225\ The Commission defined incremental cost 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, and purchased and 
interchange power costs and taxes.'' Id. at P 9 n.17 (citing 
Consumers Energy Co., 87 FERC ] 61,170 at 61,179 (1999).
---------------------------------------------------------------------------

    227. A variety of different deviation bands and pricing methods are 
on file for generator imbalances. Rates for generator imbalance 
underdeliveries range from the greater of $100/MWh or 110 percent of 
system incremental cost to the greater of $150/MWh or 200 percent of 
the incremental cost.\226\ Generator imbalance rates for overdeliveries 
range from 90 percent \227\ of system decremental cost to 50 percent 
\228\ of the decremental cost.
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    \226\ See Duke Energy Corp., Docket No. ER05-855-000 (Dec. 20, 
2005) (unpublished letter order) (accepting Duke Electric 
Transmission's Large Generator Interconnection Agreement with Power 
Ventures Group, LLC (Duke Delegated Letter Order)).
    \227\ See Entergy Services, Inc., 90 FERC ] 61,272 (2000) 
(concerning various generator imbalance agreements).
    \228\ See Duke Delegated Letter Order.
---------------------------------------------------------------------------

    228. In the NOI, we asked several questions about the need to 
modify the treatment of energy and generator imbalances. For example, 
with respect to energy imbalances, the Commission asked whether the 
deviation band of 1.5 percent continues to be appropriate 
and whether penalty charges should be eliminated entirely for 
transmission customers, or whether transmission customers should be 
charged no more than the control area's cost of supplying energy to 
correct the imbalance. With respect to generator imbalances, the 
Commission asked if comparability in the treatment of generator 
imbalances is needed, how generator imbalances should be priced, and 
whether a generator imbalance provision should be included as a 
schedule in the pro forma OATT rather than in generator interconnection 
agreements.\229\
---------------------------------------------------------------------------

    \229\ NOI at P 31.
---------------------------------------------------------------------------

Comments
    229. Many commenters assert that the deviation band of 1.5 percent 
for energy imbalances continues to be appropriate. EEI argues that the 
deviation band for energy imbalance service is reasonable because it 
appropriately balances the need to protect transmission system 
reliability and the need for operational flexibility. LG&E argues that 
the deviation band of 1.5 percent and associated penalties 
for transactions that fall outside this band are an appropriate means 
of disciplining market participants. Southern argues that allowing a 
larger deviation band could encourage gaming and leaning on the system, 
which ultimately would jeopardize reliability. Southern adds that 
allowing deviations of more than 1.5 percent without penalty could 
cause, among other things, inefficient use of generation resources and 
inappropriate cost shifting from those most able to control imbalances 
to those lacking such control.
    230. Several commenters assert that the deviation band for energy 
imbalances should be modified. APPA argues that imbalances outside the 
deviation band currently must be paid off at rates that often bear no 
resemblance to the actual cost that the transmission provider likely 
incurs to deal with the imbalance. APPA recommends revising Schedule 4 
to increase the deviation band and to institute a graduated series of 
increasing penalties outside of the expanded deadband. Public Power 
Council states that there is no forecast model that accurately predicts 
actual fluctuations in loads within the deviation band and therefore 
penalties will not induce parties to schedule more accurately. Public 
Power Council states that the 1.5 percent deviation band encourages 
loads to over-schedule and encourages the Commission to either expand 
the deviation band or adopt a multi-band system similar to the one 
Bonneville has in place. Snohomish notes that Bonneville has two 
deviation bands beyond the 1.5 percent that have greater penalties when 
customers cannot manage their energy imbalances within the first 
deviation band and states that this approach seems equitable because it 
gives customers the proper incentives to keep their schedules accurate.
    231. Constellation argues that the Commission should eliminate 
energy imbalance penalties and require that imbalances be netted across 
all suppliers and with respect to each customer. EPSA contends that 
imbalances outside the deviation band should be netted on a system-wide 
basis and settled at incremental costs. Snohomish states that it 
prefers an approach that provides for netting and penalizes intentional 
deviation. Nevada Companies explains that its energy imbalance tariff 
nets all negative and positive imbalances such that penalties are only 
invoked if there is a net positive or a net negative imbalance outside 
of the deviation band. PPL also advocates that the Commission should 
allow suppliers the flexibility to net and trade imbalances in areas 
where no imbalance market exists.
    232. Duke contends that requiring transmission providers to supply 
imbalance service at a system incremental cost may eliminate the 
erroneous perception that the existing charges are discriminatory, but 
such an approach does nothing to solve the problems that imbalances 
cause, nor does such an approach reflect the actual costs of leaning on 
and dumping on the system. A number of commenters argue that penalties 
should be imposed because without penalties there is insufficient 
economic incentive for transmission customers to properly schedule and, 
as such, reliability could be harmed.\230\ WAPA states that if a 
balancing authority has very limited generation capacity (either 
physical or market) available for the provision of energy imbalance 
service, the assessment of penalties is warranted in order to establish 
a disincentive to improper behavior that potentially may affect 
reliability.
---------------------------------------------------------------------------

    \230\ E.g., MidAmerican, NorthWestern, PacifiCorp, PNM-TNMP, 
Powerex, Progress Energy, Salt River, and Southern.
---------------------------------------------------------------------------

    233. Powerex notes that some mechanism should be in place that 
distinguishes between intentional or repeated deviations and unit 
outages or force majeure events and argues that penalties should be 
tiered so that they increase exponentially as a generator's imbalances 
increase.
    234. With regard to generator imbalances, EEI, Entergy, 
MidAmerican, and Southern contend that the Commission should continue 
its current policy, as established in Order No. 2003, of requiring that 
generator imbalances be addressed either in the OATT or in the 
generator interconnection agreement. EEI, MidAmerican and Entergy 
contend that the Commission

[[Page 32672]]

should retain the flexibility of transmission providers to deal with 
the issue of generator imbalances on a case-by-case basis, subject to 
the requirement that they do not engage in unduly discriminatory or 
preferential treatment with respect to other generators on the system. 
Calpine contends that requiring transmission providers to treat 
generator imbalances in the pro forma OATT in the same way regardless 
of the generator, and in all control areas, would provide greater 
certainty and consistency for generators and help to eliminate the 
opportunity for transmission providers to engage in discriminatory 
behavior. Bonneville argues that its three-tiered pricing and penalty 
approach for energy imbalances also is appropriate for generator 
imbalances.
    235. PNM-TNMP states that the 1.5 percent deviation band for 
imbalance service continues to be appropriate except for intermittent 
resources. For those resources, it maintains, imbalance energy costs 
should not be punitive, but rather should be designed to allow the 
transmission provider to recover its full costs of providing the 
generator imbalance service. NRECA urges the Commission not to revise 
imbalance provisions in a manner that singles out wind generators for 
preferential treatment. Northwestern, on the other hand, argues that a 
generator imbalance service schedule should be included in the pro 
forma OATT for intermittent resources and the service should not apply 
to traditional generators.
    236. Commenters argue that the treatment of imbalances should be 
made comparable with the treatment of inadvertent energy for 
transmission providers. APPA argues that Schedule 4 raises concerns 
about discriminatory treatment because Schedule 4 is not applicable to 
OATT transmission providers, who clear their imbalances through the use 
of inadvertent interchange, if they operate their own control areas. 
TDU Systems contend that transmission providers that operate control 
areas hold a competitive advantage over non-control area operators 
solely by virtue of the fact that they have access to balancing 
options, such as inadvertent interchange, that are not available to all 
market participants, including customers of the transmission providers. 
TDU Systems argue that this advantage can be decisive when sellers that 
do not operate control areas try to compete with control area operators 
for sales to entities concerned about exposure to the penalties imposed 
under existing imbalance tariff provisions.\231\ East Texas 
Cooperatives argue that control area utilities, moreover, enjoy a 
double benefit because: (1) They are not subject to penalties 
themselves, and (2) the control area operator's own generation is used 
to provide imbalance service to the other transmission customers in the 
control area. TAPS asserts that comparability requires affording 
transmission dependent utilities the same return-in-kind treatment 
control areas use for inadvertent energy. It maintains that, at a 
minimum, the Commission should eliminate the $100/MWh penalty, except 
in egregious circumstances and/or the Commission should expand the 
return-in-kind deviation band substantially.
---------------------------------------------------------------------------

    \231\ Accord APPA, Constellation, EPSA, Steel Manufacturers 
Association, and TAPS.
---------------------------------------------------------------------------

    237. EEI and Entergy, on the other hand, argue that inadvertent 
energy and energy imbalances are not comparable and should thus be 
treated differently. EEI states that a NERC-certified control area is 
responsible for supporting the reliability of its own area as well as 
supporting the reliability of the interconnected power system grid. EEI 
explains that the inadvertent energy that a control area experiences 
reflects the moment-by-moment netting of load, generation and schedules 
into or out of the control area, and that inadvertent energy reflects 
the loads, generator output and schedules of all entities within the 
control area, and not simply the loads and generation of the 
transmission provider. Entergy explains that control area interchange 
imbalances may involve the failure of control areas to match their 
scheduled inflows and outflows due to contingencies occurring even in 
another control area.\232\
---------------------------------------------------------------------------

    \232\ Accord Progress Energy, Salt River, and Southern.
---------------------------------------------------------------------------

Discussion
    238. The existing energy imbalance charges under Schedule 4 of the 
pro forma OATT and the generator imbalance charges described in Order 
No. 2003 are the subject of significant concern and confusion in the 
industry. The Commission is concerned about the variety of different 
methodologies used for determining imbalance charges and whether the 
level of the charges provides the proper incentive to keep schedules 
accurate without being excessive. The Commission proposes to modify the 
current pro forma OATT Schedule 4 treatment of energy imbalances and to 
adopt a separate pro forma OATT schedule for the treatment of generator 
imbalances. More specifically, the Commission seeks to balance the 
needs of transmission providers to operate their transmission systems 
in a reliable manner with the needs of transmission customers to have 
reasonable access to those systems at just and reasonable rates, as 
well as the needs of a variety of transmission customers with different 
generator sources.
    239. To achieve this, the Commission proposes to create new energy 
and generator imbalance schedules based on the following 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.
    240. Bonneville has taken an energy imbalance pricing approach that 
appears consistent with the three principles outlined above and seems 
to be working well. Bonneville's imbalance pricing approach is based on 
a three-tiered deviation band that would appear workable for both 
energy imbalance service and generator imbalance service. Under this 
proposal, imbalances of less than or equal to 1.5 percent of the 
scheduled energy (or two megawatts, whichever is larger) would be 
netted on a monthly basis and settled financially at 100 percent of 
incremental or decremental cost at the end of each month. Imbalances 
between 1.5 and 7.5 percent of the scheduled amounts (or two to ten 
megawatts, whichever is larger) would be settled financially at 90 
percent of the transmission provider's system decremental 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. Imbalances greater than 7.5 percent of the scheduled 
amounts (or 10 megawatts, whichever is larger) would be settled at 75 
percent of the system decremental cost for overscheduling imbalances or 
125 percent of the incremental cost for underscheduling imbalances. 
Intermittent 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.

[[Page 32673]]

    241. The Commission seeks comment on whether this approach should 
be adopted for inclusion in the pro forma OATT for energy and generator 
imbalances. Does this approach provide sufficient incentives to ensure 
that transmission systems can be operated in a reliable manner and 
ensure that customers are treated in a just and reasonable manner?
    242. We note that the Bonneville provision allows for greater 
charges when a customer has an ``intentional deviation.'' \233\ We seek 
comment on whether the pro forma OATT imbalance provision should 
provide for penalties for behavior that represents deliberate reliance 
on the transmission provider's generation resources, as opposed to 
scheduling errors, with such penalties being subject to prior notice 
and approval by the Commission and based on the facts and circumstances 
of the individual transmission provider.
---------------------------------------------------------------------------

    \233\ See 2006 Transmission and Ancillary Service Rate 
Schedules, approved in United States Dep't of Energy--Bonneville 
Power Administration, 112 FERC ] 62,258 (2005). The Bonneville 
tariff provides that ``For any hour(s) that an imbalance is 
determined by [Bonneville] to be an Intentional Deviation: (1) No 
credit is given when energy taken is less than the scheduled energy, 
(2) When energy taken exceeds the scheduled energy, the charge is 
the greater of: (i) 125% of [Bonneville's] highest incremental cost 
that occurs during that day, or (ii) 100 mills per kilowatthour.'' 
An ``Intentional Deviation'' is defined as ``a deviation that is 
persistent during multiple consecutive hours or at specific times of 
the day,'' a ``pattern of under-delivery or over-use of energy,'' or 
``persistent over-generation or under-use during Light Load Hours, 
particularly when the customer does not respond by adjusting 
schedules for future days to correct these patterns.'' Id. at 46.
---------------------------------------------------------------------------

    243. If the Commission adopts revised energy and generator 
imbalance schedules consistent with the principles proposed in this 
NOPR, that would eliminate the need for a final rule in the Imbalance 
Provisions Proceeding in Docket No. RM05-10-000 concerning generator 
imbalance provisions for intermittent resources. As such, the 
Commission would expect to terminate that docket concurrent with the 
adoption of revised energy and generator imbalance schedules in this 
proceeding.
    244. With respect to the pricing of energy and generator 
imbalances, the Commission believes that charges based on incremental 
costs or multiples of incremental costs will provide the proper 
incentive to keep schedules accurate without being excessive. In 
deriving such charges, the Commission proposes that incremental cost be 
defined to include both energy and commitment \234\ costs (to the 
extent additional commitments are needed). The Commission seeks comment 
on how such charges should be calculated, as well as how they would be 
applied to transmission customers. How should additional demand and 
energy costs, if incurred in responding to imbalances, such as 
redispatch, commitment, or additional regulation reserves be 
appropriately reflected in the calculation of imbalance charges and 
which customers should be charged for such costs? Who should receive 
any additional revenue from the charges above incremental costs?
---------------------------------------------------------------------------

    \234\ ``Capacity commitment'' generally is defined as the 
generating capacity committed by a utility to provide capability for 
another utility to attain its reserve level. See, e.g., Central & 
South West Services, Inc., 48 FERC ] 61,197 at 61,731 n.9 (1989).
---------------------------------------------------------------------------

    245. The Commission proposes to continue to allow inadvertent 
energy to be treated differently than energy and generator 
imbalances.\235\ The Commission believes that these two types of 
service are not comparable. Inadvertent energy represents the 
difference between a control area's net actual interchange and the net 
scheduled interchange. It is caused by the combined effects of all the 
generation and loads in the control area and not simply the loads and 
generation of the transmission provider. Further, management of 
inadvertent energy is needed to adhere to NERC standards and to ensure 
reliability. Many of the variables of inadvertent interchange are 
beyond the control of individual transmission providers. Because of the 
nature of inadvertent energy and historical practices, transmission 
providers pay back imbalances in kind, and the Commission has accepted 
this treatment as just and reasonable. In contrast, allowing customers 
to pay back all energy and generator imbalances in kind would not 
provide sufficient incentives for them to minimize imbalances. Some 
commenters have argued that the return-in-kind approach to inadvertent 
energy between control areas is discriminatory because OATT customers 
are required to bear actual charges for their imbalances. As we have 
described, we believe the two services are different and hence do not 
believe that the two should have precisely the same treatment. However, 
we seek comment on whether the current return-in-kind approach to 
inadvertent energy encourages leaning on the grid in times of shortage, 
and therefore whether any reforms in this area are appropriate. Would 
pricing inadvertent energy at incremental cost (or some variant 
thereof) be an appropriate disincentive? If any reforms in this area 
are appropriate, should they be pursued under FPA section 215 as part 
of the review of reliability standards?
---------------------------------------------------------------------------

    \235\ See Order No. 888-A at 30,233.
---------------------------------------------------------------------------

    246. Furthermore, we propose to add provisions to schedule 4--
Energy Imbalance Service and schedule 9--Generator Imbalance Service of 
the pro forma OATT to reflect the Commission's policy that a 
transmission provider may only charge a transmission customer for 
either hourly generator imbalances or hourly energy imbalances for the 
same imbalance, but not both.\236\ We also clarify that this policy 
only applies to a transmission customer that otherwise would be charged 
for both generator imbalances and energy imbalances for the same 
imbalance occurring within the same control area.
---------------------------------------------------------------------------

    \236\ Imbalance Provisions Proceeding at 32,123 (citing Niagara 
Mohawk, 86 FERC at 61,028).
---------------------------------------------------------------------------

    247. Finally, the Commission seeks comment on whether or not it is 
appropriate to allow a transmission customer to net energy and 
generator imbalances for a particular transaction within a single 
control area to the extent they offset. For example, if a transmission 
customer schedules 100 MWh over an hour but has a load of 120 MWh, it 
would face an imbalance of 20 MW. However, if it also dispatches its 
generation to the same 120 MWh, should there be no net charge? 
Similarly, what if a transmission customer schedules 100 MWh but has a 
load of 80 MWh and dispatches its generation to 80 MWh? Does the 
potential to allow netting for offsetting imbalances contradict the 
principle of encouraging good scheduling practices? We also seek 
comment on what would be a reasonable percentage to net without 
concerns that allowing such netting would lead to reliability concerns 
from using unscheduled transmission or would cause redispatch costs by 
the transmission provider.
2. Credits for Network Customers
    248. Section 30.9 of the pro forma OATT states that a network 
customer owning existing transmission facilities that are integrated 
with the transmission provider's transmission system may be eligible to 
receive cost credits against its transmission service charges if the 
network customer can demonstrate that its transmission facilities are 
integrated into the plans or operations of the transmission provider to 
serve its power and transmission customers. The section also states 
that new facilities are eligible for credits when the facilities are 
jointly planned and installed in coordination with the transmission 
provider. In the NOI, we asked several questions regarding the 
Commission's

[[Page 32674]]

policy on credits for new facilities, including whether the Commission 
should reconsider its policy of denying credits for transmission 
facilities owned by point-to-point customers.
Comments
    249. Many commenters argue that the existing credit requirement has 
the effect of discouraging joint transmission planning.\237\ NRECA 
asserts that making the existence of joint planning a condition of a 
customer's eligibility for credits or revenue requirement recovery 
simply provides another excuse for public utility transmission 
providers to refuse to engage in joint planning.
---------------------------------------------------------------------------

    \237\ E.g., Arkansas Cities, East Texas Cooperatives, Nevada 
Companies, NRECA, PNM-TNMP, Suez Energy NA, TAPS, TransAlta, TDU 
Systems, and Xcel.
---------------------------------------------------------------------------

    250. EEI contends that if the transmission provider is required to 
provide credit against the customer's cost of transmission service, the 
cost of the customer's jointly planned and integrated transmission 
facilities should be automatically added to the transmission provider's 
cost of service. EEI states that the Commission has adopted a similar 
approach with respect to third party supply of reactive capability. EEI 
also argues that automatic credit for customer facilities is 
inappropriate because in instituting open access and requiring 
transmission providers to offer network service, the Commission made it 
clear that it did not direct a merging of the parties' transmission 
systems or the operation of a joint transmission network.\238\ EEI 
argues that the Commission should retain the requirement that customer 
transmission facilities are eligible for credits from transmission 
providers other than RTOs and ISOs only if they meet the integration 
standard.
---------------------------------------------------------------------------

    \238\ For support, EEI cites Florida Municipal Power Agency v. 
Florida Power & Light Co., 74 FERC ] 61,006 at 61,009-10 (1996), 
order on reh'g, 96 FERC ] 61,130 (2001), aff'd sub nom. Florida 
Municipal Power Agency v. FERC, 315 F.3d. 362 (D.C. Cir. 2003).
---------------------------------------------------------------------------

    251. Some commenters argue that the OATT should not be reformed to 
include credits for transmission facilities built by point-to-point 
customers.\239\ EEI states that the question posed in the NOI appears 
to contemplate providing credits to a point-to-point customer who 
constructs new facilities that are jointly planned with the 
transmission provider regardless of whether those facilities meet the 
Commission's standards for integration of customer-owned transmission 
facilities. Instead, EEI argues, the Commission should apply the test 
from Consumers Energy Co., which provides that a transmission customer 
should receive credits against its transmission bill when the 
transmission provider uses facilities owned by that customer to provide 
service to other transmission customers.\240\ Bonneville and PNM-TNMP 
state that if applied to existing facilities, credits for point-to-
point customers could cause major cost shifts. Bonneville argues that 
these problems would be especially severe in the Northwest, where there 
are numerous areas of multiple transmission ownership, both in series 
and in parallel, and where transmission owners purchase large amounts 
of transmission from each other. Southern states that to effectuate 
this proposal, the Commission would need to revise its ``higher of'' 
pricing requirements, otherwise no point-to-point customer would build 
transmission facilities when it can require the transmission provider 
to do so and costs are rolled into rate base. Entergy opposes providing 
credits for transmission facilities owned by point-to-point service 
customers because those facilities are not used to integrate resources 
and loads in the same way that facilities owned by network customers 
are.
---------------------------------------------------------------------------

    \239\ E.g., Bonneville, EEI, and PNM-TNMP.
    \240\ EEI cites Consumers Energy Co., 86 FERC ] 63,004 at 65,016 
(1999), order on initial decision, 98 FERC ] 61,333 (2002) and 
Northeast Texas Electric Cooperative, Inc., 111 FERC ] 61,189 at P 6 
(2005).
---------------------------------------------------------------------------

    252. Other commenters argue that the Commission should modify the 
pro forma OATT to include a provision allowing credits for transmission 
facilities built by a point-to-point customer.\241\ TAPS states the 
Commission should re-evaluate its bright line denial of credits for 
transmission facilities owned by point-to-point customers. TAPS 
contends that the current section 30.9 integration test may be 
appropriate for long-term (e.g., at least 5 years) point-to-point 
customers. South Carolina E&G supports modifying the pro forma OATT to 
provide credits for facilities built by point-to-point customers, but 
asserts that credits should apply only when the customer's facilities 
are in service. South Carolina E&G states that after the passage of a 
defined period of inactivity, such as when a customer takes a facility 
out of service, the credits should be suspended, to reduce the burden 
on other customers.
---------------------------------------------------------------------------

    \241\ E.g., MidAmerican, South Carolina E&G, TAPS, and Williams.
---------------------------------------------------------------------------

Discussion
    253. Section 30.9 of the pro forma OATT establishes two categories 
of facilities owned by network customers that are eligible for credits. 
First, existing transmission facilities ``integrated with the 
Transmission Provider's Transmission Systems,'' are eligible for 
credits if the network customer can ``demonstrate that its transmission 
facilities are integrated into the plans or operations of the 
Transmission Provider to serve its power and transmission customers.'' 
The second category comprises new facilities (i.e., facilities 
constructed by the network customer after the service commencement date 
in the OATT), if the facilities ``are jointly planned and installed in 
coordination with the Transmission Provider.''
    254. We agree with the commenters who argue that section 30.9 
should be reformed. We agree that the link between credits for new 
facilities and the requirement for joint planning can act as a 
disincentive to coordinated planning, which is contrary to the 
Commission's original objective in adopting the provision. A 
transmission provider has an incentive to deny coordinated planning if 
it believes that the cost of any facilities constructed as a result of 
that process will have to be borne in significant part by its bundled 
retail customer.
    255. Therefore, we propose to sever the link between credits and 
planning, and treat the two issues separately within the pro forma 
OATT.\242\ Eliminating the link is appropriate because the crediting of 
integrated facilities serves a purpose independent of the planning 
obligation. Traditionally, the Commission has allowed a transmission 
provider to allocate the costs of integrated facilities to all users of 
the integrated system or grid consistent with the view that the entire 
grid is interconnected and provides generalized benefits to all 
users.\243\ But because integration is a fact-specific matter, the 
Commission in Order No. 888 decided that credits were appropriately 
addressed on a case-by-case basis. \244\
---------------------------------------------------------------------------

    \242\ See Part V.B for a discussion of our proposed planning 
obligations.
    \243\ See, e.g., Pacific Gas and Electric Co., 106 FERC ] 61,144 
at P 12, reh'g denied, 108 FERC ] 61,297 (2004); Niagara Mohawk 
Power Corp., 42 FERC ] 61,143 at 61,531 (1988); Otter Tail Power 
Co., 12 FERC ] 61,169 at 61,420 (1980).
    \244\ Order No. 888 at 31,742.
---------------------------------------------------------------------------

    256. Regarding the eligibility for credits, as the Commission 
stressed in Order No. 888, while certain facilities may warrant some 
form of cost credit, the mere fact that transmission customers may own 
transmission facilities is not a guaranteed entitlement

[[Page 32675]]

to such credit.\245\ Rather, a network customer's transmission 
facilities must provide additional benefits to the transmission grid in 
terms of capability, delivery options, and reliability, and be relied 
upon for the coordinated operation of the grid. The integration 
standard, in brief, requires that to be eligible for credits under pro 
forma OATT section 30.9, 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.'' 
\246\ This policy is premised on the principle that ``just as the 
transmission provider cannot charge the customer for facilities not 
used to provide transmission service, the customer cannot get credits 
for facilities not used by the transmission provider to provide 
service.'' \247\ The Commission continues to believe that, for existing 
facilities, the integration standard is the appropriate standard for 
determining whether a network customer's facilities should be eligible 
for credits. We clarify, however, that for new facilities, the 
integration standard must be applied comparably,\248\ because 
application of the integration test in a manner that exclusively 
benefits the transmission provider is unduly discriminatory, and a 
violation of the FPA.\249\ Specifically, we propose that the network 
customer shall receive credit for transmission facilities added 
subsequent to the effective date of the Final Rule in this proceeding 
provided that: (1) Such facilities are integrated into the operations 
of the transmission provider's facilities, and (2) if the transmission 
facilities were 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.
---------------------------------------------------------------------------

    \245\ Order No. 888 at 31,742-43.
    \246\ 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).
    \247\ Id. at P 20 (citing Order No. 888-A at 30,271 & n.277); 
accord East Texas Coop., Inc. v. Central & South West Services, 
Inc., 108 FERC ] 61,079 at P 28 (2004), reh'g denied, 114 FERC ] 
61,027 (2006); Southern California Edison Co., 108 FERC ] 61,085 at 
P 10 (2004); Northern States Power Co., 87 FERC ] 61,121 at 61,488 
(1999); Florida Municipal Power Agency v. Florida Power & Light Co., 
74 FERC ] 61,006 at 61,010 (1996), reh'g denied, 96 FERC ] 61,130 at 
61,544-45 (2001), aff'd sub nom. Florida Municipal Power Agency v. 
FERC, 315 F.3d 362 (D.C. Cir. 2003).
    \248\ In Order No. 888, the Commission addressed the 
comparability requirement:
    We caution all transmission providers that while our discussion 
here addresses the requirements necessary for a customer's 
transmission facilities to become eligible for a credit, the 
principles of comparability compel us to apply the same standard to 
the transmission provider's facilities for rate determination 
purposes.
    Order No. 888 at 31,743 n.452.
    \249\ Credits may not be necessary if the transmission provider 
and a transmission customer jointly own the transmission facilities 
and operate those facilities under the terms of a joint ownership 
agreement. See Northern States Power Co., 83 FERC ] 61,098 at 61,472 
(explaining that the crediting provision in pro forma OATT section 
30.9 was not intended to apply to jointly owned transmission 
facilities), order on clarification, 83 FERC ] 61,338, order denying 
reh'g and clarification, 84 FERC ] 61,122 (1998), remanded on other 
grounds sub nom. Northern States Power Co. v. FERC, 176 F.3d 1090 
(8th Cir. 1999).
---------------------------------------------------------------------------

    257. Thus, the Commission proposes revising section 30.9 to 
eliminate the disincentive to coordinated planning and investment in 
the transmission grid (i.e., by deleting language that permits 
transmission providers to refuse crediting for network-customer-owned 
facilities that are not part of its planning process) and provide for 
non-discriminatory crediting for integrated facilities comparable to 
those transmission provider facilities that are included in rates. We 
are proposing this change to ensure that section 30.9 does not impede 
coordinated planning and to otherwise ensure that our crediting policy 
is just, reasonable and not unduly discriminatory. Our action is not in 
any way intended to lessen our commitment to coordinated planning 
between a transmission provider and its customers. To the contrary, we 
propose elsewhere in the NOPR to require coordinated planning by all 
transmission providers. This requirement is not linked to the issue of 
crediting for customer-owned facilities, but rather is a general 
requirement intended to avoid opportunities for undue discrimination in 
transmission planning.
    258. We decline to allow transmission providers as part of this 
proceeding to automatically add costs of credits associated with 
integrated transmission facilities to the transmission provider's cost 
of service. These costs typically are considered and evaluated as part 
of a regular cost of service review process. Nevertheless, a 
transmission provider that wishes to add an automatic adjustment clause 
to its rates may seek Commission approval for its methodology in a 
filing submitted under section 205 of the FPA.\250\
---------------------------------------------------------------------------

    \250\ See, e.g., id. at 61,467.
---------------------------------------------------------------------------

    259. Finally, the Commission does not propose revising the pro 
forma OATT to expressly allow transmission credits for facilities owned 
by point-to-point customers. Unlike a network customer, a point-to-
point customer only pays for a discrete transmission service over the 
contract term. The network customer takes a usage-based service which 
integrates its resources and loads and pays on the basis of its total 
load on an ongoing basis. The transmission provider includes the 
network customer's resources and loads in its long-term planning 
horizon and the two parties coordinate operations of their facilities 
through a network operating agreement. In this way, network service is 
comparable to the service that the transmission provider uses to serve 
its own retail native load, and credits for certain integrated network 
facilities are appropriate. The point-to-point customer, however, does 
not purchase integration service, nor does it sign a network operating 
agreement with the transmission provider. Thus, because of the inherent 
differences between point-to-point and network service, we do not 
propose adding a new OATT requirement that the transmission provider 
make credits generically available to point-to-point customers that own 
transmission facilities. Nevertheless, there may be some facilities 
owned by a point-to-point customer that meet all the criteria for 
credits. Although the Commission is not including a specific provision 
in the OATT that provides credits for these facilities, consistent with 
the Commission's statement in Order No. 888, the Commission will 
address such situations on a fact-specific, case-by-case basis.\251\
---------------------------------------------------------------------------

    \251\ Order No. 888 at 31,742; Order No. 888-A at 30,271.
---------------------------------------------------------------------------

3. Capacity Reassignment
    260. In Order No. 888, the Commission concluded that a public 
utility's tariff must explicitly permit the voluntary reassignment of 
all or part of a holder's firm point-to-point capacity rights to any 
eligible customer.\252\ As for the rate for capacity reassignment, the 
Commission concluded that it could not permit reassignments at market-
based rates because it was unable to determine that the market for 
reassigned capacity was sufficiently competitive so that assignors 
would not be able to exert market power. Instead, the Commission capped 
the rate at the highest of: (1) The original transmission rate charged 
to the purchaser (assignor), (2) the transmission provider's maximum 
stated firm transmission rate in effect at the time of the reassignment 
or (3) the assignor's own opportunity costs

[[Page 32676]]

capped at the cost of expansion (price cap).\253\
---------------------------------------------------------------------------

    \252\ Order No. 888 at 31,696; pro forma OATT section 23.1.
    \253\ Order No. 888 at 31,697.
---------------------------------------------------------------------------

    261. The Commission explained in Order No. 888 that opportunity 
cost pricing had been permitted at ``the higher of embedded costs or 
legitimate and verifiable opportunity costs, but not the sum of the two 
(i.e., `or' pricing is permitted; `and' pricing is not).'' \254\ In 
Order No. 888-A, the Commission explained that opportunity costs for 
capacity reassigned by a customer should be measured in a manner 
analogous to that used to measure the transmission provider's 
opportunity cost.\255\ As a result, the Commission required that 
assignors proposing to recover opportunity costs file with the 
Commission a fully developed formula describing the derivation of 
opportunity costs. The Commission further required that all information 
necessary to calculate and verify opportunity costs must be made 
available to the eligible customer.\256\
---------------------------------------------------------------------------

    \254\ Id. at 31,740.
    \255\ Order No. 888-A at 30,224.
    \256\ See id.; Order No. 888 at 31,740.
---------------------------------------------------------------------------

    262. In the NOI, the Commission asked whether the price cap 
remained reasonable, or whether it should be modified or eliminated to 
further encourage capacity reassignment.
Comments
    263. Some commenters argue that the price cap should not be 
eliminated.\257\ According to EEI, transmission pricing policies do not 
have much impact on reassignment of capacity rights, so changes to the 
approach would be largely irrelevant.
---------------------------------------------------------------------------

    \257\ E.g., Ameren, EEI, Southern, and Tacoma Power.
---------------------------------------------------------------------------

    264. Southern contends that elimination of the price cap might 
result in inefficiencies by providing an incentive for entities to 
hoard transmission capacity. Moreover, Tacoma and Public Power Council 
reason that because transmission remains a monopoly business, cost-
based rates remain appropriate.
    265. Snohomish expresses concern that eliminating the price cap may 
encourage speculation in the purchase of transmission capacity, greatly 
driving up costs for transmission customers. Snohomish, nonetheless, 
states that auctions of secondary capacity may be appropriate, provided 
the capacity is purchased under a long-term contract for the purpose of 
serving load and the sale does not reduce transmission capacity for 
existing customers that have contracted for the capacity.
    266. Other commenters argue that the price cap should be 
revised.\258\ Exelon supports the maximum flexibility possible in use 
of the transmission system, including allowing transmission rights to 
be assigned and redirected--so long as the transfer capability is 
available and existing service will not be curtailed. Exelon recommends 
that the Commission modify the OATT to permit transmission customers to 
charge market-based rates for transmission capacity in the secondary 
market. This change, Exelon argues, would provide greater incentive for 
the owner of the transmission right to actively pursue reassigning the 
transmission service, thereby using the transfer capability more 
efficiently. Alcoa states that economic incentives are needed to enable 
a secondary transmission capacity market to develop and thrive.
---------------------------------------------------------------------------

    \258\ E.g., Alcoa, Constellation, EPSA, Exelon, and MidAmerican.
---------------------------------------------------------------------------

    267. EPSA and Constellation argue that the only desirable 
modification to this pricing policy would be to eliminate the 
requirement that transmission customers file with the Commission a 
method to impose opportunity cost pricing. EPSA states that to its 
knowledge, no transmission customer has yet been able to develop and 
file a predefined formula mechanism that would serve as an opportunity 
cost rate, probably because opportunity cost pricing reflects dynamic 
market conditions. MidAmerican claims that even when there is no 
disagreement over the assignor's determination of opportunity costs, 
considerable time may be required to prepare and obtain approval from 
the Commission of the resulting FPA section 205 filing. EPSA asserts 
that the market itself will cap the value of reassignment at the price 
the transmission provider would charge, i.e., its expansion cost. 
Constellation states that prices of reassigned capacity will be 
disciplined by the opportunity costs of releasing the capacity. Both 
Constellation and EPSA state that the Commission should recognize that 
opportunity costs for released transmission capacity are dynamic and 
provide a market discipline on the price that any seller will charge 
and any purchaser will pay for reassigned capacity. In response to 
EPSA's proposal to eliminate the requirement that transmission 
customers file with the Commission a method to impose opportunity cost 
pricing, APPA argues that to ensure that the price a seller would 
charge for firm transmission capacity is just and reasonable, as the 
FPA requires, the Commission should require such a filing.
    268. While Cinergy maintains that the current pricing approach for 
capacity assignments is appropriate, it supports consideration of new 
alternatives that would allow more effective capacity reassignment by 
the transmission customer. Cinergy asserts that one area that could be 
considered is to require the transmission provider to provide more 
clarity on how reassignment requests are analyzed for approval and the 
options available to the transmission customer to post existing service 
for reassignment.
    269. Williams and Powerex argue that revising the price cap will 
not encourage greater capacity reassignment. Williams submits that 
other non-price limitations on capacity reassignment--such as the 
requirement that the assignee utilize the same source and sink as the 
original customer--are the real reasons there has not been more 
capacity reassignment. Stated differently, Williams contends that the 
price cap does not restrict capacity reassignment--source and sink 
requirements do.
Discussion
    270. In Order No. 888, the Commission explained that it expected 
capacity reassignment to achieve three goals: ``(1) help [customers] 
manage the financial risks associated with their long-term transmission 
commitments, (2) reduce the market power of transmission providers by 
enabling customers to compete, and (3) foster efficient capacity 
allocation.'' \259\ Because capacity reassignment does not appear to 
have developed into a competitive alternative to primary capacity, the 
Commission is proposing modifications to its existing pricing policy. 
We propose removing the price cap on capacity reassignment and allowing 
negotiated rates for transmission capacity reassigned by transmission 
customers. We do not propose to lift the price cap for capacity resold 
by transmission providers or their affiliates due to market power 
concerns.
---------------------------------------------------------------------------

    \259\ Order No. 888 at 31,696.
---------------------------------------------------------------------------

    271. The Commission notes that transmission customers have not used 
the opportunity cost pricing option for capacity reassignment. Comments 
suggest that this may be due in part to the complexity of establishing 
an opportunity cost formula, or the administrative hurdle of filing and 
supporting a proposal. Simply put, the goals of the capacity assignment 
program remain important to the

[[Page 32677]]

Commission, but the price cap has not served as a useful means of 
achieving them. While we recognize that other factors may inhibit 
capacity reassignment, eliminating the price cap should provide more 
flexibility to market participants and encourage customers to sell 
their capacity to another customer who values the capacity more highly. 
It also will facilitate the release of capacity and encourage the 
maximum number of voluntary transactions to occur in a secondary 
market, which will benefit all market participants consistent with the 
Commission's goals for capacity reassignment.
    272. Although in Order No. 888 the Commission decided not to allow 
reassignment at market-based rates because of concerns that capacity 
assignors might exert market power, due to several factors, we now 
believe that market forces will limit the ability of most assignors to 
exert market power. First, we expect that competition among releasing 
customers will restrict the potential exercise of market power. Second, 
the Commission will monitor the market by requiring quarterly reports 
and regular OASIS postings from transmission providers based on 
information submitted to them from reassigning customers regarding 
their reassignment activity (including the negotiated rate). The 
Commission's complaint procedures and the Enforcement Hotline also are 
available for participants raising market power concerns, which should 
supplement the Commission's existing market oversight efforts. Third, 
the continued regulation of rates for primary capacity will act as a 
check to ensure just and reasonable reassignment rates. For example, 
without congestion on the transmission system, the transmission 
provider's rate on file serves as the de facto price cap and, if 
congestion exists, the ``incremental rate,'' which reflects the 
transmission provider's cost of expansion, should act as a price 
ceiling for long-term transactions.
    273. The Commission concludes that because the price cap appears to 
have reduced customers' transmission options, removal of the price cap 
is warranted without a market-by-market analysis. Our reform is 
intended to provide alternatives for customers that value the capacity 
more highly. The Commission finds that lifting the price cap strikes a 
reasonable balance between promoting more efficiency through trading 
and relying upon competition and price disclosure to prevent 
anticompetitive behavior. Though we recognize that the price of 
reassigned capacity may temporarily exceed the cost of expansion, that 
price signal is an important economic incentive to induce greater 
transmission investment.
    274. Concerns have been raised that allowing negotiated rates may 
provide an incentive to ``hoard'' capacity, or to reserve transfer 
capability for no legitimate use other than to speculate on the price 
of the reassigned capacity. The ability of a transmission customer to 
hoard capacity is not without limits in that the transmission provider 
has the obligation to resell as non-firm point-to-point service any 
firm point-to-point transfer capability reserved by a customer but not 
scheduled within the time-frames established in pro forma OATT section 
13.8. As discussed above, we believe that the incentive for the 
transmission customer to hoard would be limited by the transmission 
provider's cost of expansion for long-term transactions. Thus, we 
believe that the greater efficiency created by a more effective 
capacity trading market for customers who need capacity during peak 
periods outweighs such concerns and that hoarding concerns are 
overstated. However, we seek comment on whether circumstances exist 
where unaffiliated transmission customers could amass market power 
similar to that of the transmission provider.
    275. We do not propose lifting the price cap for all assignors. A 
stated goal of capacity reassignment is to ``reduce the market power of 
transmission providers by enabling customers to compete.'' \260\ 
Commission precedent has allowed transmission provider affiliates to 
reassign capacity under the price cap,\261\ and we propose to continue 
this policy. To allow transmission providers and their affiliates to 
use negotiated rates allows the transmission provider to use its 
primary market power in the secondary market. A transmission provider 
not subject to a price cap would have the ability and incentive to 
exercise market power to favor its own generation sales when it 
operates and administers the reassignment process. Furthermore, lifting 
the cap for the transmission provider may eliminate the incentive to 
build or expand, as it may allow the transmission provider to take 
advantage of congested pathways to charge rates above the cost of 
expansion. Because these expected outcomes would reduce the ability of 
other customers to compete, and undermine the development of a viable 
secondary market, we conclude that it remains appropriate to require 
transmission providers and their affiliates to conform to the price cap 
for capacity reassignment.
---------------------------------------------------------------------------

    \260\ Id.
    \261\ Commonwealth Edison Co., 78 FERC ] 61,312 at 62,336 
(1997).
---------------------------------------------------------------------------

    276. The Commission seeks comment on the quarterly reports and 
OASIS postings we propose to require from transmission providers under 
this proposal. They will be based on information that we will require 
assignors to give to transmission providers. What information should we 
require in the quarterly reports and OASIS postings, i.e., information 
about the capacity released, the original rate paid for that capacity, 
the price charged to the assignee for the capacity, and the term of the 
assignment? Is other information necessary for operational and 
reliability purposes? Are additional reports by assignors to the 
transmission provider necessary, and if so, what information should be 
reported by assignors? Should the Commission establish a new quarterly 
reporting process, e.g., a new form, or utilize the existing electronic 
electric quarterly report procedures? How frequently should the OASIS 
postings be made?
4. ``Operational'' Penalties
 a. Unauthorized Use Penalties
    277. Section 13.7 of the pro forma OATT stipulates that a point-to-
point service customer's use of the transmission system may not exceed 
the firm capacity it has reserved at each point of receipt and each 
point of delivery except as specified in section 22 of the pro forma 
OATT.\262\ Section 13.7 of the pro forma OATT also directs the 
transmission provider to specify the rate treatment and all related 
terms and conditions for an unauthorized use operational penalty in the 
event that a point-to-point customer exceeds its firm reserved capacity 
at any point of receipt or point of delivery. Section 14.5 of the pro 
forma OATT contains similar provisions for an unauthorized use penalty 
in the event that a transmission customer exceeds its non-firm point-
to-point service capacity reservation. The pro forma OATT does not 
otherwise address unauthorized use penalties.
---------------------------------------------------------------------------

    \262\ Section 22 (Changes in Service Specifications) of the pro 
forma OATT prescribes the circumstances under which the transmission 
customer may modify the point of delivery and the point of receipt 
for an existing firm point-to-point service reservation.
---------------------------------------------------------------------------

    278. In Allegheny Power, the Commission capped unauthorized use 
penalties at a level equal to twice the standard rate for the service 
at issue.\263\ In addition, the Commission clarified that the standard 
rate to be used as the

[[Page 32678]]

basis of the unauthorized use penalty charge must be that of the 
service at issue, without regard to the duration of the violation; 
i.e., if overuse occurs for one hour, but the service overused is 
weekly service, the penalty charge is to be capped at twice the 
standard weekly rate.\264\ In APS, the Commission issued an audit 
report to Arizona Public Service Company (APS) that contains two 
findings that Commission audit staff characterized as unauthorized use 
of transmission service.\265\ In the first finding, APS's wholesale 
merchant function did not request and pay for point-to-point service to 
support some of the off-system power sales it made at trading hubs 
where APS system resources were directly connected. In the second 
finding, APS incorrectly treated the Phoenix Valley 230kV system as a 
single node on its transmission system. As a result, off-system sales 
made by generators connected to the Phoenix Valley system should have 
been, but were not, supported by point-to-point service. Other than 
these cases, the Commission has not addressed the appropriate method of 
applying unauthorized use penalties pursuant to the provisions of 
sections 13.7 and 14.5 of the pro forma OATT.
---------------------------------------------------------------------------

    \263\ Allegheny Power System, Inc., 80 FERC ] 61,143 at 61,545-
46 (1997) (Allegheny Power).
    \264\ Id. at 61,546 n.131.
    \265\ Arizona Public Service Co., 109 FERC ] 61,271 at P 6 
(2004) (APS).
---------------------------------------------------------------------------

Comments
    279. MidAmerican states that unauthorized use penalties should only 
be imposed if the pro forma OATT clearly specifies that they are 
applicable to a proscribed conduct.
Discussion
    280. We propose to clarify the circumstances under which we would 
expect transmission providers to assess unauthorized use penalties. 
This clarification will eliminate a potential source of discretion in 
the implementation of the pro forma OATT and will assist the Commission 
in its enforcement of the obligations imposed by it. Specifically, we 
propose to clarify that unauthorized use penalties apply to any 
circumstance when a transmission customer uses transmission service 
that it has not reserved.\266\ An unauthorized use penalty would be 
assessed in circumstances when a transmission customer has a 
transmission service reservation, but uses transmission service in 
excess of its reserved capacity. An unauthorized use penalty also would 
be assessed if a transmission customer uses transmission service when 
it does not have a transmission service reservation, including the 
situations described in APS. We further clarify that an unauthorized 
use penalty would not be assessed in circumstances when a transmission 
customer inappropriately uses a network service reservation to support 
an off-system sale, as discussed in Part V.D.7. However, a transmission 
customer that inappropriately uses network service would be required to 
pay for the point-to-point service it should have reserved and could be 
subject to a civil penalty depending on the circumstances. We seek 
comment on whether the current policy that limits unauthorized use 
penalties to twice the standard rate for the service at issue has 
resulted in penalties that are not just and reasonable; and, if so, we 
seek comment regarding provisions that would yield unauthorized use 
penalties that are just and reasonable.
---------------------------------------------------------------------------

    \266\ The revised pro forma OATT reflects this proposed reform 
in sections 13.7 and 30.4.
---------------------------------------------------------------------------

b. How Transmission Providers Should Pay Operational Penalties
Comments
    281. In the NOI, the Commission observed that the existing pro 
forma OATT allows transmission providers to impose certain operational 
penalties against transmission customers for violations of the pro 
forma OATT, but does not address the adverse consequences to a 
transmission provider who violates its OATT.
    282. Several commenters indicate that a transmission provider would 
not face the same financial consequence as other transmission customers 
when the transmission provider or an affiliated transmission customer 
pays an operational penalty. TAPS notes that applying customer-focused 
penalties to the transmission provider is meaningless if a transmission 
provider merely pays itself. EPSA suggests that the Commission include 
provisions in the new pro forma OATT to ensure that the penalty imposes 
a true financial consequence, e.g., penalties imposed on a transmission 
provider should be distributed to those OATT customers that were taking 
service during the period in which the violation occurred. ELCON 
suggests that the pro forma OATT be revised to provide for tariff-based 
sanctions against a transmission provider that fails to comply with its 
OATT. Occidental argues that one of the fundamental problems with the 
current OATT is the lack of tariff-based penalties for violations. 
Occidental states that tariff-based penalties are needed to focus 
transmission providers on compliance and to permit customers and the 
Commission's enforcement staff to bring both specific tariff violations 
and general issues of non-compliance before the Commission.
Discussion
    283. We propose to have transmission providers pay non-offending, 
unaffiliated transmission customers when the transmission provider or 
its affiliate incurs operational penalties. This proposal is consistent 
with our prior findings that operational penalties collected by the 
transmission provider should be credited back to non-offending 
transmission customers in order to provide an incentive to the 
transmission provider to develop non-penalty remedies that will elicit 
appropriate behavior by transmission customers.\267\ For those 
transmission providers subject to operational penalties, we propose to 
require the transmission provider to make an annual compliance filing 
to notify the Commission of the amounts of all such operational 
penalties incurred during the year and to propose a method to identify 
non-offending, unaffiliated transmission customers to which the 
transmission provider would distribute penalty amounts. In addition, we 
propose to allow a transmission provider to avoid an annual compliance 
filing by making a one-time filing to propose a mechanism through which 
it would identify non-offending, unaffiliated transmission customers 
and a method by which it would distribute the operational penalties it 
or its affiliates have incurred to the identified transmission 
customers. We also propose to prohibit transmission providers from 
recovering for ratemaking purposes or through any service or facility 
under the Commi-sion's jurisdiction any cost it incurs when it or an 
affiliate pays an operational penalty.
---------------------------------------------------------------------------

    \267\ See, e.g., Carolina Power & Light Co., 103 FERC ] 61,209 
(2003); Regulation of Short-Term Natural Gas Transportation Services 
and Regulation of Interstate Natural Gas Transportation Services, 
Order No. 637, 65 FR 10156 (Feb. 25, 2000), FERC Stats. & Regs. ] 
31,091 at 31,315 (2000) (noting that ``to the extent that penalty 
revenues are generated, the required crediting of penalty revenues 
will eliminate any economic incentive for pipelines to rely on 
penalties rather than inducements''); order on reh'g, Order No. 637-
A, 65 FR 35705 (Jun. 5, 2000), FERC Stats. & Regs. ] 31,099 (2000).
---------------------------------------------------------------------------

5. ``Higher of'' Pricing Policy
    284. 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

[[Page 32679]]

Statement.\268\ The Commission has explained that when rolling in the 
costs of network upgrades incurred to meet a transmission service 
request would have the effect of raising the average embedded cost rate 
paid by existing customers, the transmission provider may elect to 
charge an incremental cost rate for the new service and thereby 
insulate existing customers from the costs of any necessary system 
upgrades. However, the transmission provider may not charge both an 
incremental cost rate and an embedded cost rate associated with 
existing network transmission facilities.\269\
---------------------------------------------------------------------------

    \268\ 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 Statutes and Regulations ] 31,005 at 31,146 (1994), order on 
reconsideration, 71 FERC ] 61,195 (1995) (Transmission Pricing 
Policy Statement).
    \269\ See Northeast Utilities Service Company (Re: Public 
Service Company of New Hampshire), Opinion No. 364-A, 58 FERC ] 
61,070 (1992), reh'g denied, Opinion No. 364-B, 59 FERC ] 61,042, 
order granting motion to vacate and dismissing request for 
rehearing, 59 FERC ] 61,089, aff'd in part and remanded in part sub 
nom. Northeast Utilities Service Company v. FERC, 993 F.2d 937 (1st 
Cir. 1993), order on remand, 66 FERC ] 61,332, reh'g denied, 68 FERC 
] 61,041 (1994) pet. denied; Pennsylvania Electric Co., 58 FERC ] 
61,278, reh'g denied, 60 FERC ] 61,034 (clarifying pricing policy), 
reh'g denied, 60 FERC ] 61,244 (1992), aff'd sub nom. Pennsylvania 
Electric Co. v. FERC, 11 F.3d 207 (D.C. Cir. 1993).
---------------------------------------------------------------------------

    285. Although we are not undertaking generic transmission pricing 
reform in this proceeding, we are concerned that our existing policies 
may not be being applied consistently and, as a result, customers may 
be quoted prices that are not consistent with the ``higher of'' policy. 
We understand that customers typically are quoted an incremental rate 
in the form of a total dollar amount of needed facility upgrades (e.g., 
$5,000,000) rather than in the form of a monthly transmission rate that 
can be compared, on an ``apples-to-apples'' basis, to the embedded cost 
rate. Presenting an incremental rate as a lump sum payment request is 
inconsistent with our ratemaking policy and has the potential to 
discourage customers from proceeding with service requests.\270\ As we 
have noted, under our ``higher of'' pricing policy for network 
upgrades, the transmission provider should compare the monthly revenue 
requirement from the upgrade to the monthly revenue requirement from 
the embedded transmission rate.\271\ We also have said that the 
incremental rate should be established by amortizing the cost of the 
upgrades over the life of the contract.\272\ Presenting the incremental 
charge in the form of a monthly rate allows a customer seeking a lower 
rate to choose to request a longer transaction term.
---------------------------------------------------------------------------

    \270\ Southwest Power Pool, Inc., 100 FERC ] 61,096 (2002) 
(designing a rate to include a balloon payment is not a substitute 
for a properly designed rate).
    \271\ Southwest Power Pool, Inc., 112 FERC ] 61,319 at P 33 
(2005).
    \272\ Southwest Power Pool, Inc., 98 FERC ] 61,256 (``We agree 
with SPP that the amortization period for upgrade costs should match 
the contract period. * * * As the customer is only obligated to take 
service for the term of the contract, it is reasonable that the 
costs only be amortized over the term of the contract.''); reh'g 
denied in pertinent part, 100 FERC ] 61,096 (2002).
---------------------------------------------------------------------------

    286. We encourage comments on whether changes to the pro forma OATT 
are necessary to ensure that incremental costs are presented as monthly 
rates for service.

D. Non-Rate Terms and Conditions

    287. In this section, we propose a number of reforms to non-rate 
terms and conditions of service under the pro forma OATT. We propose 
these reforms to eliminate opportunities for undue discrimination, to 
ensure that the services offered under the pro forma OATT are just and 
reasonable, to increase the transparency of service being provided, and 
to provide clarity with respect to terms and conditions that have 
caused confusion in the industry.
1. Potential Modifications to Long-Term Firm Point-to-Point Service
    288. In Order No. 888, the Commission required all public utilities 
to offer both firm and non-firm point-to-point service and firm network 
service on a non-discriminatory open access basis.\273\ In the NOI, the 
Commission asked for comments on pricing policies that can create an 
incentive to maximize the use of the transmission system.\274\ Also, 
the Commission asked whether the OATT should require transmission 
providers to offer new transmission services, such as conditional firm, 
partial firm, and seasonal firm service.\275\ Further, the Commission 
asked in the NOI whether deviations from the ``higher of'' pricing 
policy would encourage greater incremental pricing of redispatch 
service.\276\
---------------------------------------------------------------------------

    \273\ Order No. 888 at 31,690.
    \274\ NOI at P 13.
    \275\ Id. at P 13.
    \276\ Id. at P 12.
---------------------------------------------------------------------------

Comments
    289. Some commenters support the inclusion of a required new 
service and contend that the existing rules for long-term firm point-
to-point service pose barriers to new entry. Constellation states that 
new products are needed that facilitate the efficient use of the 
transmission system in a competitive market. AWEA and EPSA argue that a 
long-term request for service from a new generator can be denied 
because there are reliability violations in only a few hours of a year, 
even though firm service is nonetheless available for the large 
majority of hours of the year. They also argue the existing grid is 
underutilized and that these practices only exacerbate this problem. 
EPSA further states that some transmission provider base case models 
show that the transmission provider is operating its system to serve 
its bundled retail native load under contingencies that the 
transmission provider would not accommodate for an OATT customer.
    290. PPL argues that the Commission should enforce the requirement 
in section 13.5 of the pro forma OATT that transmission providers must 
redispatch to relieve congestion that may only occur during a few hours 
a year. PPL further contends that transmission providers have the 
incentive to simply deny requests for transmission over a path that 
experiences occasional congestion, rather than properly undertake 
redispatch actions to minimize this congestion. Others state that they 
have not received an offer by a transmission provider to redispatch to 
accommodate a request for transmission service, but instead are given 
no choice but to pay for facilities studies that are costly and time 
consuming.\277\ Entergy states in its reply comments that it only 
evaluates redispatch as part of a system impact study if requested by 
the transmission customer.
---------------------------------------------------------------------------

    \277\ E.g., AWEA, Arkansas Cities, EPSA, and Renewable Energy.
---------------------------------------------------------------------------

    291. Several commenters suggest that pricing complexities and 
certainty of recovery must be resolved before requiring mandatory 
redispatch. These commenters state that the cost of redispatch is more 
than the fuel cost differential and includes hard to quantify costs 
such as start-up costs, higher capital costs due to shorter life and 
accelerated replacement, higher maintenance costs, and potential 
emergency power purchases to serve load in constrained areas.\278\
---------------------------------------------------------------------------

    \278\ E.g., Ameren, EEI, Progress Energy, and Southern.
---------------------------------------------------------------------------

    292. PacifiCorp suggests that the higher charge, whether embedded 
costs or redispatch costs, be determined on a monthly basis rather than 
making a one-time determination prior to commencement of service. 
PacifiCorp argues that the typical cost analysis fails to consider the 
complexity of determining redispatch. PacifiCorp contends that cost 
estimates become increasingly unreliable as the analysis

[[Page 32680]]

extends over time, and the complications of one-year transmission 
service agreements with rollover options make an accurate calculation 
nearly impossible.
    293. AWEA provides a detailed proposal for conditional firm 
service, in which the transmission provider would identify certain 
months, weeks, or days when firm transmission service may be limited or 
unavailable and identify the number of potential hours during those 
conditional times, when the customer could have its reservations cut or 
reduced prior to any firm customer reductions. Under specified 
conditions, for a limited number of hours over a set number of 
``conditional'' months, weeks, days or hours, the firm service may be 
reduced day-ahead by the transmission provider, with conditional firm 
service provided instead in those hours firm service is unavailable. 
The ``conditional'' periods would be established when the service is 
offered. Also, capacity commitments for conditional firm service would 
be accounted for in ATC calculations prior to new sales of short-term 
firm transmission service. Commenters support a requirement that 
transmission providers post on OASIS the paths for which conditional 
firm service is available, clearly listing the available capacity for 
each period, and hours during which firm service is available or 
curtailment is possible as a result of congestion.\279\
---------------------------------------------------------------------------

    \279\ E.g., EPSA and PPL.
---------------------------------------------------------------------------

    294. Those supporting conditional firm service argue that it should 
be offered to customers requesting long-term firm service when firm ATC 
is not available during all hours of the request, and allow the 
transmission customer to obtain service when it would otherwise be 
denied.\280\ As for the rate design of the service, EPSA and PPL 
recommend that it include either a discount from the firm rate to 
reflect the reduction in use at the system peak or no discount from the 
firm rate, but customers taking conditional firm service would have a 
right of first refusal when firm service becomes available for the 
hours in which they have agreed to be curtailed.
---------------------------------------------------------------------------

    \280\ E.g., AWEA, Constellation, EPSA, MidAmerican, PPL, and 
Renewable Energy.
---------------------------------------------------------------------------

    295. Commenters arguing against a requirement to provide 
conditional firm service argue that it would degrade the quality of 
service received by existing long-term firm point-to-point and network 
customers.\281\ Also, Bonneville argues that providing conditional firm 
service would require modification to the current curtailment 
priorities in the OATT and the design and purchase of systems to track 
the purchases and implement the more complex curtailment schemes. TAPS 
notes that PacifiCorp amended its OATT to make more explicit the 
potential for granting part of a request for firm service in terms of 
both the amounts of service and/or the periods of time for which there 
is sufficient ATC.\282\ If the Commission develops new services, TAPS 
contends that the Commission should build on PacifiCorp's OATT 
amendments. Many commenters that object to requiring new transmission 
services recommend that the Commission encourage transmission providers 
to develop and adopt new services in response to customer needs.\283\ 
Ameren explains that this process should result in additional services 
being provided that meet the needs of the customers, that are 
physically feasible considering the existing uses of the system, and 
that do not adversely affect the service provided to other users of the 
system and are not unduly discriminatory. Finally, several commenters 
express a general sentiment against requiring a service that may not be 
suited to all regions or systems.\284\
---------------------------------------------------------------------------

    \281\ E.g., APPA Reply Comments, Powerex, and Salt River.
    \282\ See PacifiCorp Open Access Transmission Tariff, section 
19.7, FERC Electric Tariff, Fifth Revised Volume No. 11, Substitute 
Original Sheet No. 100 (effective April 26, 2004); see also 
PacifiCorp Open Access Transmission Tariff, Schedule 7, Long-Term 
Firm Point-To-Point Transmission Service, section 2, FERC Electric 
Tariff, Fifth Revised Volume No. 11, First Revised Sheet No. 252 
(effective April 1, 2006) (rates for partial delivery of long-term 
firm point-to-point transmission service).
    \283\ E.g., Ameren, Bonneville, Cinergy, EEI, KCP&L, Nevada 
Companies, NRECA, Salt River, Sempra Global, Southern, TVA, and 
WAPA.
    \284\ E.g., Ameren, Cinergy, Salt River, and Southern.
---------------------------------------------------------------------------

    296. Commenters also expressed support for services aside from, or 
in addition to, conditional firm service. Exelon proposes that the 
Commission should require ``seasonal firm'' service, though other 
commenters ask if seasonal firm service would invite hoarding or 
``cream skimming.'' MidAmerican contends that in most cases, the need 
for seasonal service can be accommodated by multiple consecutive 
purchases of monthly service. PPL supports a required ``partial firm'' 
service that is confirmed and available on a firm basis but provided in 
various amounts over an annual period. PPL states that the amount of 
partial firm service offered would be shaped to match the available 
capacity within each interval or the year. Powerex and WAPA argue long-
term priority non-firm point-to-point service is the most workable new 
service.
    297. MidAmerican states that various transmission providers 
interpret and apply the provisions of section 19.7 (Partial Interim 
Service) of the pro forma OATT in different ways. MidAmerican states 
that the Commission should clarify whether section 19.7 refers to a 
partial period of service (i.e., granting firm service for the full MW 
amount of the initial request, but for only a portion of the requested 
time period), or a partial quantity of service (i.e., granting firm 
service for the time period of the initial request, but for only a 
portion of the requested full MW amount). MidAmerican suggests that the 
revised OATT should provide that partial interim service be offered 
both for partial periods and for partial quantities.
    298. Bonneville states that, currently, when a customer accepts an 
offer of partial service, Bonneville keeps the remaining portion of the 
customer's request in the queue if the customer executes a system 
impact study agreement. Bonneville contends that the Commission's OASIS 
Standards and Communication Protocols, however, appear to disallow this 
result, as does standard OASIS functionality. Bonneville asks that the 
Commission clarify whether the Commission intends that a customer 
accepting an offer of partial service should lose its position in the 
queue.
    299. EPSA further argues that transmission providers should be 
required to accommodate a request for any service, whether or not 
articulated in the new OATT, to the extent they can do so, on a 
nondiscriminatory basis and without unreasonably affecting reliability. 
EPSA also states that the burden should be on the transmission provider 
to state in writing why it cannot accommodate any given request.
Discussion
Proposed Findings
    300. The Commission preliminarily finds that the existing methods 
for evaluating requests for long-term firm point-to-point service may 
no longer be just, reasonable and not unduly discriminatory. We believe 
that transmission providers may evaluate transmission availability to 
serve long-term transmission service requests in a manner that is not 
comparable with the method they use to evaluate transmission needs for 
bundled retail native load and, therefore, that certain reforms are 
necessary to ensure comparability.
    301. When a transmission provider considers new resources to serve 
its bundled retail native load, the

[[Page 32681]]

transmission provider will not eliminate an otherwise economic option 
because the resource may not be deliverable in a few hours of the year. 
Rather, the transmission provider will evaluate whether it can 
redispatch its resources as necessary to ensure that load is served on 
a reliable and economic basis. If redispatch is needed in only a few 
hours of the year, the transmission provider typically will not 
construct new facilities to accommodate new resources. Rather, the 
transmission provider will look for a resource at a different location 
to fulfill its needs on a least cost basis taking into account 
transmission and energy costs. This use of redispatch to accommodate a 
new resource means that the resulting service is provided even though 
the transmission provider's power flow studies show that ATC is not 
available in all hours of the year. In this situation, the new resource 
receives a firm service that is not currently available on many systems 
to OATT customers because the transmission provider uses redispatch on 
a long-term basis to accommodate a new resource for which ATC is not 
available in every hour; in some respects, this firm service is similar 
to conditional firm service because it uses firm transmission capacity 
to serve bundled retail native load even though the resource is not 
deliverable in every hour of the year.
    302. The Commission believes that the current practices for 
evaluating long-term transmission service requests generally may not 
reflect the same practices used to evaluate transmission needs to serve 
bundled retail native load. Under current practices, the transmission 
provider evaluates whether service can be granted in every hour of the 
year that is modeled and, if not, it informs the customer that long-
term firm transmission service cannot be provided out of existing 
transmission capacity. Section 19.3 of the pro forma OATT provides that 
a system impact study is required before the transmission provider must 
identify available redispatch options. Before redispatch options are 
offered, however, the customer must also agree to fund a facilities 
study to determine whether redispatch is less expensive than the 
transmission facilities upgrades.\285\ Thus, it is only if the customer 
requests a system impact study and facilities study, and agrees to pay 
for the studies, that the request will be evaluated further and the 
option of redispatch will be offered to the customer. This study 
process is both time consuming and expensive. More importantly, it 
differs from the evaluation typically undertaken by the transmission 
provider in deciding whether transmission is available to serve bundled 
retail native load with a new resource.
---------------------------------------------------------------------------

    \285\ See pro forma OATT section 27.
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    303. In Order No. 888, the Commission's goal was to ``facilitate 
the development of competitively priced generation supply options, and 
to ensure that wholesale purchasers of electric energy can reach 
alternative power suppliers and vice versa.'' \286\ The first part of 
this goal, development of competitive supplies, has been realized to 
some degree.\287\ However, the lack of transmission access threatens 
the viability of customer alternatives to their traditional suppliers. 
Without long-term firm service, it is difficult for alternative 
suppliers to procure the financing they need for project development. 
Customers taking non-firm point-to-point service have a lower 
reservation priority and are subject to curtailment and interruption 
more frequently than network customers taking transmission service from 
resources other than designated network resources. Thus, the lack of 
long-term firm transmission access being provided on a 
nondiscriminatory basis is a significant problem in realizing the goals 
of Order No. 888.
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    \286\ Order No. 888 at 31,646.
    \287\ In 2004, electric generation from IPPs represented an 
increasing share of the wholesale markets with nearly 36 percent of 
total sales, a significant increase from 1996 when they accounted 
for only 12 percent of total sales. In 2004, IPPs accounted for 36 
percent of generator nameplate capacity compared to 56.5 percent for 
utilities and 7.5 percent for combined heat and power. Office of 
Coal Nuclear Electric and Alternative Fuels, Energy Information 
Administration, Electric Power Annual 2004 at 9 (2005).
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    304. The Commission's preliminary view is that current practices do 
not adequately reflect the manner in which transmission service is 
planned for bundled retail native load and may no longer be just, 
reasonable and not unduly discriminatory. Transmission customers, 
especially those customers seeking service to or from new generation 
resources, must be given greater flexibility of service to meet their 
needs comparable with the flexibility provided on behalf of bundled 
retail native load. New generation resources often face a grid that 
cannot accommodate requests for long-term firm transmission, at least 
not without the significant delay required by transmission 
construction, despite the fact that redispatch options may exist that 
would allow that resource to be accommodated. In sum, maintaining the 
status quo, as advocated by several commenters, may be insufficient to 
ensure comparable treatment of new generation resources for all 
transmission customers, eliminate barriers to entry for new generation 
sources seeking long-term transmission arrangements, and encourage the 
efficient and flexible use of the transmission system in a competitive 
market.
Proposed Solutions
    305. The Commission believes there are two basic options for 
addressing this problem.\288\ The first option focuses on generation 
redispatch to accommodate long-term firm point-to-point service, while 
the second option creates a modified form of firm point-to-point 
service that includes non-firm service in a defined number of hours of 
the year when firm point-to-point service is not available. The 
Commission's preliminary view is that the redispatch option is superior 
because it: (1) Mirrors the way that transmission providers plan for 
bundled retail native load, (2) would provide firm service to new 
entrants, rather than service that is subject to more frequent 
curtailment in certain hours of the year, and (3) may avoid certain 
implementation issues associated with designing a modified long-term 
point-to-point service. However, we seek comment on this preliminary 
view and on both of the options outlined below.\289\
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    \288\ We will continue to encourage transmission providers to 
propose other services requested by customers or such services that 
may meet their customers' and systems' needs as energy markets 
evolve. However, the Commission does not propose to require 
transmission providers to provide any service other than the 
services expressly set forth in the pro forma OATT. In response to 
EPSA, the decision to provide a new OATT service in the first 
instance remains with the transmission provider. Moreover, several 
of the proposals included in this NOPR such as lifting the price cap 
associated with capacity reassignment for firm point-to-point 
service and hourly firm point-to-point service should provide 
transmission customers with greater service flexibility.
    \289\ We also request comment on the applicability of these two 
options for transmission providers who operate RTOs or ISOs. Because 
RTOs provide redispatch service and the ability to access 
transmission with no prior reservation by paying congestion charges, 
they may not need to reform their existing procedures to satisfy our 
proposal with respect to redispatch. We also note that conditional 
firm service has the potential to disturb the link between long-term 
service and the allocation of Financial Transmission Rights (FTRs) 
or auctions of FTR rights.
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Redispatch Service
    306. The Commission believes that full utilization of generation 
redispatch is the preferred method of ensuring that long-term point-to-
point service is not unduly discriminatory and does not serve as a 
deterrent to new entry. The preferred approach is described below.
    307. Section 13.5 of the pro forma OATT requires the transmission

[[Page 32682]]

provider to expand or upgrade its transmission system or, if it is more 
economical, to redispatch its resources to provide requested firm 
point-to-point service without: (1) Degrading or impairing the 
reliability of service to native load customers, network customers and 
other transmission customers taking firm point-to-point service; or (2) 
interfering with the transmission provider's ability to meet prior firm 
contractual commitments to others. The cost of any redispatch performed 
pursuant to section 13.5 is to be specified in the service agreement 
prior to initiating service and charged to the transmission customer 
consistent with Commission policy. For network service, section 33.2 of 
the pro forma OATT also requires all network customers to agree to 
redispatch their network resources, along with transmission provider's 
own resources, to relieve a constraint that may impair reliability. 
Section 33.3 of the pro forma OATT provides that the costs of 
reliability redispatch performed pursuant to section 33.2 are to be 
shared between network customers and the transmission provider on a 
load-ratio share basis.\290\
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    \290\ Order No. 888-A at 30,267.
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    308. To encourage the provision of redispatch as an option to 
facilitate use of the existing transmission grid, we propose to revise 
the pro forma OATT to require the offer of redispatch prior to the 
performance of a facilities study. We note that the system impact 
study, as defined by the pro forma OATT, is the transmission provider's 
assessment of the adequacy of its grid to accommodate a request for 
firm point-to-point or network service and whether any additional costs 
may be incurred to provide the requested service. It is followed by a 
facilities study, which is defined as an engineering study to determine 
the transmission system modifications necessary to provide the 
requested service, including cost and scheduled completion date. 
Neither study references the steps necessary to evaluate the cost of 
redispatch that could be performed in lieu of expanding the grid. 
Therefore, we propose that the transmission provider must, as part of 
the system impact study process, include an estimate of the number of 
hours of redispatch that may be required to accommodate the request for 
transmission service, and a preliminary estimate of the cost of that 
redispatch. The customer would then be given the option of having the 
transmission provider perform the necessary studies to determine the 
projected redispatch costs or perform the facilities study, or both.
    309. Consistent with the existing requirements of the OATT, the 
redispatch requirement would apply to the redispatch of the 
transmission provider's own generation resources and would not require 
the transmission provider to purchase new resources to provide this 
service.\291\ However, we propose to require the transmission provider, 
when it cannot accommodate a long-term firm point-to-point transmission 
request through redispatch of its own resources, to identify the 
generators in other control areas that could relieve the constraint on 
the affected flowgates to allow the transmission customer to seek 
redispatch with transmission providers in adjacent control areas to 
remove such constraints. We also seek comment on whether to expand the 
existing OATT obligation to require the transmission provider to 
redispatch not just its own resources, but those of its network 
customers also, subject to the network customers receiving appropriate 
compensation when their resources are redispatched.
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    \291\ However, we also request comment on whether it would be 
appropriate to require the transmission provider to contract to 
purchase generation from outside of its control area if it would 
facilitate a firm transaction. We note that at least one redispatch 
provisions currently in use contemplates the use of third-party 
generation for redispatch. See Deseret Generation and Transmission 
Cooperative, Inc. (Deseret) FERC Electric Tariff, First Revised 
Volume No. 2 (Deseret OATT), accepted for filing in Deseret 
Generation and Transmission Cooperative, Inc., Docket No. ER01-2642-
000 (Aug. 27, 2001) (unpublished letter order). Attachment J of 
Deseret's OATT states, in part: ``If redispatch services are 
provided under this Attachment J, the [t]ransmission [p]rovider will 
in good faith attempt to relieve the constraint by the least-cost 
means, whether by seeking a change in generation output from the 
[t]ransmission [p]rovider's [m]erchant [f]unction or from any other 
feasible generator or by other means including facilitating the 
payment of firm transmission customers to temporarily give up their 
rights to relieve the constraint.'' Deseret OATT, Attachment J, Part 
I.D, Original Sheet No. 340 (effective July 1, 2001).
---------------------------------------------------------------------------

    310. Another issue that arises is how the redispatch option should 
be priced. The pro forma OATT caps the cost of redispatch at the cost 
of constructing the network upgrades needed to facilitate the requested 
transmission service. Some commenters discuss what costs should be 
included in a redispatch rate, such as start-up costs, higher 
maintenance costs and fuel differentials, and state that inclusion of 
these charges would send clearer price signals and induce transmission 
investments.\292\
---------------------------------------------------------------------------

    \292\ E.g., Ameren, EEI, Progress Energy, and Southern.
---------------------------------------------------------------------------

    311. Establishing a formula rate for redispatch costs may be one 
way to ensure greater use of this option, both to facilitate long-term 
requests for service and to grant customers greater flexibility in 
choosing resources on a daily or hourly basis. A redispatch pricing 
proposal could include a MW quantity, the incremental cost of fuel 
(increasing the supply of fuel) at the point of delivery, and the 
decremental cost of fuel (decreasing the supply of fuel) at the point 
of receipt capped at the price of fuel. These costs could be calculated 
based on the difference between the cost of ramping up a generator at 
the point of delivery and ramping down a generator at the point of 
receipt.\293\ We invite comments on whether including such a formula in 
the transmission provider's OATT would facilitate redispatch and 
whether it should account for other, hard-to-quantify costs such as 
those listed by EEI: Start-up costs, higher capital costs due to 
shorter life and accelerated replacement, higher maintenance costs, and 
potential emergency power purchases to serve load in constrained areas. 
One option might be to establish a standard per kWh fee for such costs, 
as was initially done for ancillary service costs.
---------------------------------------------------------------------------

    \293\ For example, redispatch costs = 75 MW x ($60 incremental 
cost at the point of delivery - $15 decremental cost at the point of 
receipt) = $3,375.
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    312. There are few examples of functioning redispatch programs on 
which to base any kind of generic change to the pro forma OATT. 
However, the Commission has approved OATT provisions for SPP \294\ 
(prior to its becoming an RTO) and Deseret.\295\
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    \294\ See Southwest Power Pool, Inc., 82 FERC ] 61,267, 
modified, 82 FERC ] 61,285, order on reh'g, 85 FERC ] 61,031 (1998); 
Southwest Power Pool, Inc., 84 FERC ] 61,055 (1998).
    \295\ See supra note 291.
---------------------------------------------------------------------------

    313. The redispatch provisions in SPP's OATT permitted a 
transmission customer facing a constrained path to decide whether to: 
(1) Go forward with its requested transmission service, (2) obtain 
relinquished capacity (solicit from holder of firm transmission rights 
the price at which they would relinquish their rights subject to the 
caps), (3) reduce transmission service to match the level of ATC 
without redispatch, (4) pay for redispatch, or (5) forego the 
transmission transaction.
    314. Under Attachment H of SPP's OATT (Redispatch Procedures and 
Redispatch Costs for Short-Term-Firm Point-to-Point Transmission 
Service Subject to Redispatch Cost) the charges to be paid by the 
transmission customer for redispatch service could not exceed the 
charges the transmission customer would have paid under SPP's point-to-
point tariffs. Stated differently, SPP capped the redispatch charges at 
a level

[[Page 32683]]

that ensures that total charges did not exceed the total charges the 
customer would have paid under individual company tariffs. For 
generation resources, the redispatch included the higher of incremental 
or replacement fuel costs and incremental operation and maintenance 
costs of generation facilities necessary to relieve constraints on the 
transmission system.
    315. The redispatch provisions in Deseret's OATT are designed to 
track cost causation with redispatch costs and contains features 
similar to the SPP OATT provisions such as providing customers with the 
opportunity to obtain relinquished capacity. Like SPP, the redispatch 
costs in Deseret's OATT are capped at the cost incurred by the 
transmission provider to provide the requested service. Under 
Attachment J of Deseret's OATT (Redispatch Protocol), generally the 
redispatch costs are calculated by multiplying the redispatch quantity, 
in MWh, that is required to satisfy the transmission customer's 
schedule in that hour by the redispatch price. Attachment J of 
Deseret's OATT also includes provisions for crediting and netting of 
redispatch costs.
    316. We also are concerned that there is a great deal of complexity 
and fuel price risk in projecting years into the future the hours of 
redispatch that will be required to grant the transmission request and 
the cost of that redispatch in those hours. Moreover, because of the 
need for involvement of the transmission provider's generation arm to 
project costs associated with redispatch and the need to factor in 
unpredictable fuel costs, we are concerned about the degree of 
discretion involved in determining redispatch costs. Understandably, 
the transmission provider does not want to bear the price risk 
associated with projected fuel costs, nor does the customer. 
PacifiCorp, in its comments, describes a possible proposal that would 
calculate redispatch costs monthly and charge the higher of redispatch 
or the OATT rate each month. We request comment on whether PacifiCorp's 
proposal may be a way of addressing the complexity and risk associated 
with determining redispatch costs over a long period and allow greater 
access to otherwise unused transmission capacity on a firm basis.
    317. We ask for comment on whether all or a portion of SPP's, 
Deseret's, or PacifiCorp's proposals should form the basis for a 
generic redispatch provision that could be included in the pro forma 
OATT, as a means of ensuring that redispatch service is available and 
priced on a just and reasonable basis.
    318. Finally, we recognize that a transmission provider may need to 
coordinate with marketing affiliate or energy affiliate employees to 
arrange generation redispatch.\296\ However, such communication and 
coordination raise potential problems for the transmission provider 
regarding compliance with the Commission's Standards of Conduct, which 
require separating transmission function employees from wholesale 
marketing and energy affiliate employees.\297\ We seek comment on what 
communication and coordination protocols can be established to permit 
the provision of generation redispatch in a manner that is not unduly 
discriminatory or preferential, and consistent with the Standards of 
Conduct.
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    \296\ In this discussion, we use the terms ``transmission 
function,'' ``marketing affiliate'' and ``energy affiliate'' as 
those terms are used in the Standards of Conduct regulations. See 18 
CFR 358.3 (2005).
    \297\ See Order No. 2004 at P 85-94.
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Conditional Firm Service
    319. The Commission seeks comment on whether a modified form of 
long-term point-to-point service would be preferable to the redispatch 
service described above. This conditional firm service option would 
address the problem of reliability limitations during certain peak 
hours by allowing the transmission provider to provide non-firm service 
to the customer in those hours. We note that at least one transmission 
provider currently provides this service pursuant to amendments to the 
partial interim service provision of its OATT,\298\ with only modest 
differences from the service described below.
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    \298\ See PacifiCorp, 98 FERC ] 61,224 at 61,885 (accepting 
revisions to section 19.7), order on reh'g, 99 FERC ] 61,259 (2002).
---------------------------------------------------------------------------

    320. As an initial matter, in response to requests for 
clarification of the partial interim service in section 19.7 of the pro 
forma OATT, we will summarize the Commission's precedent on this 
service. The Commission has clarified that partial interim service has 
a partial duration element, as well as a partial quantity element.\299\ 
For example, in Morgan Stanley, the Commission found that had the 
customer requested long-term service for a two-year period, but only 
one year was available, the transmission provider would have been 
obligated to offer service for that one available year.\300\ The 
Commission was clear, however, that partial interim service does not 
require the transmission provider to treat a request for annual service 
as if it necessarily included a request for all subsumed monthly or 
weekly durations of service during the requested year.\301\ In other 
words, a transmission provider does not need to respond to a request 
for one year of service with an offer of monthly service. The 
Commission has also interpreted section 19.7 to apply to requests for 
transmission service that have not undergone or do not necessarily 
require a system impact study or facilities study.\302\ Further, the 
Commission has required transmission providers to offer partial interim 
service even where third-parties must provide upgrades in order to 
provide for the full transmission service request.\303\ Although 
partial interim service has a duration component, it differs from 
conditional firm service, which would require the transmission provider 
to treat the request for service as if it included a request for 
monthly, weekly, daily, and hourly firm service during the year.
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    \299\ See, e.g., Idaho Power Co. v. Bonneville Power 
Administration, 96 FERC ] 61,031 at 61,080-81 (2001) (Idaho Power v. 
Bonneville) (interpreting section 19.7 to require Bonneville to 
offer 277 MW of monthly short-term firm transmission capacity 
interim service to the entity next in the queue with a request of 
577 MW); Morgan Stanley Capital Group v. Illinois Power Co., 93 FERC 
] 61,081 at 61,220 (2000) (Morgan Stanley) (``Illinois Power should 
have offered as much transmission capacity as it could provide 
continuously for the duration of the request, i.e., as many MW of 
transmission service as available for the entire one-year period 
Morgan Stanley requested.''); accord Idaho Power Co., 90 FERC ] 
61,009 at 61,018-19 (2000) (directing transmission provider to 
provide 18 months of partial interim service for a customer 
requesting eight years of service).
    \300\ Morgan Stanley at 61,220. In response to Bonneville, the 
Commission clarifies that a customer does not lose its queue 
position for its original request when it accepts a counteroffer for 
less service than originally requested.
    \301\ Id. at 61,220; Tenaska Power Services Co. v. Southwest 
Power Pool, Inc., 93 FERC ] 61,082 at 61,222-23 (2000) (both 
concluding that transmission provider has no obligation to respond 
to a long-term request with an offer of short-term service).
    \302\ See, e.g., Idaho Power v. Bonneville at 61,080-81 
(requiring an offer of partial interim service for short-term firm 
service where a system impact study is not applicable); Morgan 
Stanley Capital Group v. Illinois Power Co., 83 FERC ] 61,204 at 
61,912 (ordering partial interim service without requiring a system 
impact study or facility study), clarification granted, 83 FERC ] 
61,299 (1998), reh'g granted in part, 93 FERC ] 61,081 (2000).
    \303\ Bonneville Power Administration, 110 FERC ] 61,001 at P 
36-37 (directing Bonneville to offer to provide customer with 
whatever portion of the request it could provide on a firm basis 
after the customer's generation project was energized without 
upgrades to PacifiCorp's system and to amend the agreement after 
upgrades are completed to provide for the full amount), reh'g 
denied, 110 FERC ] 61,094 (2005).
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    321. If we decline to adopt the redispatch proposal above, any 
conditional firm service that we would order would be made available 
only to customers who request long-term firm point-to-point service. 
When the long-

[[Page 32684]]

term firm point-to-point service is not available, and the customer 
requests conditional firm service, the transmission provider would 
evaluate transmission availability for the portion of the long-term 
request that cannot be filled due to lack of ATC. The evaluation of 
conditional firm availability should occur prior to a system impact 
study or facilities study. In offering conditional firm service, the 
transmission provider must identify the number of hours during the year 
in which the conditional firm customer will have service identical to 
any other firm point-to-point service, and specify the maximum number 
of hours of the year during which firm transmission service may be 
unavailable. The conditional firm service agreement would identify the 
conditional curtailment hours, i.e., the number of potential hours 
during those conditional times when the customer could have its 
reservations cut or reduced prior to any firm customer reductions. 
Conditional firm service would include an annual cap to the conditional 
curtailment hours and we seek comment on whether it should also include 
monthly caps for each conditional month. Capacity commitments for 
conditional firm service would be accounted for in the ATC calculations 
prior to new sales of short-term firm transmission service, thus not 
degrading the value of the conditional firm transmission product.
    322. We propose that conditional firm service would be curtailed 
before firm uses until such time as curtailment of the conditional firm 
service has reached the annual or monthly caps, after which time the 
service would be treated as firm. We propose that conditional firm 
service, during conditional curtailment hours, be treated equivalent to 
secondary network service.\304\ We decline to adopt the proposed quasi-
firm curtailment priority because it would require creation of a new 
curtailment classification including a determination concerning the 
appropriate type of curtailment, i.e., choosing between pro rata 
curtailment currently used for firm transactions or full transaction 
curtailment currently used for non-firm transactions. Institution of a 
new curtailment class would require changes to curtailment protocols 
and reliability coordinators' procedures, which is potentially 
burdensome and costly. Further, as discussed below, we believe that 
conditional firm point-to-point service, as proposed, is analogous to 
the secondary network service currently used by network customers and 
therefore both services should enjoy the same curtailment priority.
---------------------------------------------------------------------------

    \304\ Secondary network service (section 28.4 of the pro forma 
OATT) refers to transmission service for network customers from 
resources other than designated network resources provided on an as-
available basis. Section 14.7 of the pro forma OATT provides that 
secondary network service is curtailed or interrupted before firm 
network or point-to-point service but after non-firm point-to-point 
service.
---------------------------------------------------------------------------

    323. We propose that customers pay the long-term firm point-to-
point rate for conditional firm service and have a right of first 
refusal when firm service becomes available for the hours in which they 
have agreed to be curtailed. This rate for conditional firm service is 
consistent with the Commission's pricing policies that promote 
maximization of long-term uses of the grid. Also, this rate makes this 
service more equivalent to secondary network service because network 
customers using secondary network service already have paid for the 
long-term use of the grid. Further, it avoids gaming incentives that a 
discounted rate could provide. For example, a discounted rate might 
provide incentives for customers to request a year of service where 
they know only three months of service is available. We seek to prevent 
this type of gaming by requiring the payment of a long-term firm rate. 
In this regard, we also expect that the long-term firm point-to-point 
rate will tend to limit the type and number of requests for conditional 
firm service. Customers will weigh the value of the service, including 
the probability of curtailment, against the cost of paying the full 
long-term firm rate, in deciding whether to queue for conditional firm 
service where customers earlier in the queue are offered, for example, 
50, 100 or 150 conditional curtailment hours.
    324. Further, we propose that customers with conditional firm 
service would qualify for rollover rights provided that they meet the 
other rollover right conditions proposed herein. The service agreement 
for conditional firm service would specify the number of conditional 
curtailment hours. The transmission provider would not be required to 
plan for service to the conditional firm customer during the 
conditional curtailment hours. We seek comment on the application of 
rollover rights to the conditional firm service.
    325. The Commission is not convinced that it is necessary to make 
this service available to network customers. Network customers enjoy 
flexibility that point-to-point customers do not, given the ability of 
network customers to use secondary network service to access resources 
other than designated resources on an as-available basis under section 
28.4 of the pro forma OATT. For example, if a network customer's 
request to designate a new network resource was denied due to lack of 
ATC, the network customer could seek secondary network service for the 
resource and receive service on an as-available basis. Such service 
would be curtailed only after all non-firm point-to-point uses sharing 
the same flowgate were curtailed. This is similar to the service that 
we now propose for point-to-point customers in the form of conditional 
firm service. We therefore tentatively conclude that conditional firm 
service is not needed by network customers, though we seek comment on 
that preliminary finding.\305\
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    \305\ Network customers pay for long-term use of the system and 
should maintain priority use of the system for secondary network 
service over those paying for non-firm use. However, because 
conditional firm customers will pay for long-term use, they should 
also maintain, for the conditional curtailment hours, a curtailment 
priority over non-firm uses equal to the curtailment priority for 
secondary network service.
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    326. We acknowledge that the obligation to provide conditional firm 
service may require the transmission provider to model its transmission 
system and the uses of its system with greater specificity. We 
recognize that all transmission providers do not use a single standard 
engineering approach to evaluate firm transmission service requests: 
some transmission providers have a single powerflow base case for each 
year studied; some use a single base case powerflow model to represent 
several future years; and others may have several seasonal base case 
powerflows for the study of future years. Transmission providers also 
use different methods to establish generator dispatch for input into 
the powerflow base case models: some transmission providers use heat-
rates without fuel prices for determining generator output in future 
years' models; some use economic unit commitment order; and others use 
projected fuel prices to establish base case powerflow generation 
output. Some transmission providers use an economic dispatch model to 
determine unit dispatch prior to establishing powerflow base cases. 
Additionally, some transmission providers must take into account 
environmental considerations, such as the pricing of emissions 
allowances, in establishing generator output for powerflow base case 
models.
    327. Regardless of the engineering approach used, in responding to 
a conditional firm request, the transmission provider would need to 
specify for the requesting customer the number of hours of firm service 
available in the year for each MW of firm service requested. This may 
require

[[Continued on page 32685]]

From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 32685-32734]] Preventing Undue Discrimination and Preference in Transmission 
Service

[[Continued from page 32684]]

[[Page 32685]]

that the transmission provider produce and examine additional powerflow 
cases or make other process changes. In order to determine the number 
of hours that the requested firm transmission capacity is unavailable, 
the transmission provider may need to model varying load conditions, 
generation and transmission planned outages, and time-contingent or 
condition-contingent generation dispatches. Generally, the greater the 
number of conditions studied, the lower the risk to the transmission 
provider of an inaccurate estimate of conditional curtailment hours. We 
recognize that there are limits to the accuracy of any prediction of 
hours of curtailment, no matter how detailed the system study.
    328. There are a number of ways for a transmission provider to 
determine the number of hours in a year when firm service is 
unavailable, i.e., the conditional curtailment hours. One method 
involves scaling down the powerflow base case. Using this method, the 
transmission provider could scale down the load and generation in the 
base case until the entire conditional firm request is available on the 
studied flowgate. For example, a base case might need to be scaled down 
to 95 percent of the summer peak demand in order to accommodate the 
conditional firm request as firm point-to-point service. The 
transmission provider would then calculate the number of hours the 
seasonal load is forecast to be 95 percent or higher to come up with 
the number of seasonal hours of curtailment for the conditional firm 
customer.
    329. Another method involves an inventory of generation and demand 
shift factors. Using this method, the transmission provider could 
determine conditional curtailment hours by adding up all the 
outstanding generation and load shift factors on the relevant flowgate. 
Once the transmission provider determines the load shift factor on the 
flowgate, it can calculate the reduction needed in regional demand to 
accommodate the conditional firm request by comparing the impact of the 
request on the power flows. The demand reduction would not necessarily 
correspond perfectly with the requested amount of service. For 
instance, a 200 MW reduction might be required to accommodate a 100 MW 
conditional firm request. Once the transmission provider determines a 
reduced load level that would accommodate the conditional firm request, 
the transmission provider would examine load forecasts to calculate the 
number of hours the load is expected to exceed this reduced load level. 
This alternative method of calculating conditional curtailment hours 
might be more burdensome than scaling down the powerflow base case 
because it requires additional data collection and analysis.
    330. Both of these methods rely on average system conditions and do 
not take into account extreme weather years or unexpected outages. 
Thus, the methods would provide an optimistic view of bulk power 
facility availability. These methods can be used to determine the 
portion of time (hours) that transmission capability will most likely 
be available and give general information on when (seasons, months) 
firm service is available.
    331. We seek comment on the most appropriate method of modeling the 
transmission system to determine the number of conditional curtailment 
hours. We also recognize that additional studies may cause additional 
costs. We seek comment on methods of ensuring recovery of these 
additional costs.
    332. We also acknowledge that provision of conditional firm service 
may require some modification to current transaction tracking 
procedures in use by the industry and require development of additional 
mechanisms. Today, transmission providers track transactions with 
curtailment priorities so that when congestion occurs transactions are 
curtailed consistent with OATT requirements, i.e., non-firm uses are 
cut before firm uses and short-term transactions are cut before longer-
term transactions. In order to implement the conditional firm service, 
transmission providers would need to determine in advance of scheduling 
deadlines whether the service should be tracked as a long-term firm use 
or to reflect the use of the conditional curtailment hours.\306\ If the 
service is treated as firm during a certain period, the transaction 
would not be cut before other firm uses. The transmission provider 
would have to perform a calculus, taking into account forecast load and 
transmission and generation availability, to determine the need to cut 
the conditional firm transaction in the next period prior to scheduling 
the transaction as conditional firm. While we do not view this as an 
insurmountable problem, we note that the decision to curtail a 
conditional firm transaction prior to other firm uses simply cannot be 
made in real time. We also note that the transmission provider would 
need to develop a mechanism to track the number of annual conditional 
curtailment hours in each service agreement and its annual or monthly 
use of those hours. Such a tracking mechanism would ensure that the 
transmission provider did not exceed the annual or monthly cap on 
conditional curtailment hours in any particular service agreement.
---------------------------------------------------------------------------

    \306\ We propose that during conditional curtailment hours, the 
transaction would be tagged with the network non-firm tag (currently 
used for secondary network service).
---------------------------------------------------------------------------

2. Hourly Firm Service
    333. The pro forma OATT contains a one-day minimum term for firm 
point-to-point service. In Order No. 888, the Commission chose a one-
day minimum over a one-hour minimum because of concerns expressed by 
commenters.\307\ There, commenters argued that comparability would not 
be achieved if some point-to-point customers were permitted to take 
service for one hour and receive the same priority as native load and 
other long-term customers that have to pay the fixed cost of the 
transmission system every hour of the year. They also expressed concern 
that a one-hour minimum term for firm point-to-point service (hourly 
firm) would promote selective use of the transmission system, impair 
the ability of a utility to plan its system, and adversely affect 
longer term transactions. Finally, some expressed concern that a one-
hour firm service may encourage speculative requests for service during 
the system peak day (a practice known as ``cream skimming'').
---------------------------------------------------------------------------

    \307\ Order No. 888 at 31,752.
---------------------------------------------------------------------------

    334. In the NOI, the Commission noted that several public utility 
transmission providers have individually filed for and received 
Commission authorization to modify their OATTs to provide hourly firm 
point-to-point service.\308\ In the NOI, the Commission sought comment 
on whether the concerns expressed in Order No. 888 remain valid, and 
whether hourly firm service should now be required. The Commission also 
asked whether hourly firm requests should be batched to allow the 
transmission provider to evaluate them as if they were a single 
request, and whether scheduling timelines for firm and non-firm hourly 
transmission service should differ.
---------------------------------------------------------------------------

    \308\ The NOI cited Entergy Services, Inc., 85 FERC 61,163 
(1998), order on reh'g, 91 FERC 61,153 (2000) and El Paso Electric 
Co., Docket No. ER04-567-000 (Apr. 9, 2004) (unpublished letter 
order).
---------------------------------------------------------------------------

Comments
    335. Some commenters support requiring transmission providers to

[[Page 32686]]

adopt hourly firm service.\309\ Alberta Intervenors and TransAlta argue 
that hourly firm service encourages trade and market liquidity. 
Regarding the concerns cited in Order No. 888, EPSA argues that, as a 
practical matter, daily firm service already receives an equal priority 
to native load and other long-term customers, and none of the concerns 
expressed in Order No. 888 have materialized. ``Cream skimming'' should 
not be a problem, EPSA continues, because firm transmission 
reservations are not cost-free, and transmission customers are unlikely 
to commit financial resources for speculative purposes. Constellation 
argues that there should be no concern that comparability will be 
eroded because hourly firm service provides additional flexibility to 
the competitive markets. PPL argues that in non-ISO/RTO regions like 
the western United States, hourly firm service could help to maximize 
the use of existing transmission facilities, increase efficiencies in 
wholesale markets, and allow customers to purchase only the amount of 
firm transmission service that they need.
---------------------------------------------------------------------------

    \309\ E.g., Alberta Intervenors, Alcoa, Calpine, Constellation, 
EPSA, HQ Energy, PPL, and TransAlta.
---------------------------------------------------------------------------

    336. Some commenters offer qualified support for hourly firm 
service.\310\ For example, South Carolina E&G states that before the 
Commission requires hourly firm service, it should obtain empirical 
market information on transmission providers' ability to provide such 
service. In its reply comments, Powerex explains that there is a 
potential for a detrimental effect if a transmission provider is not 
able to accurately determine its ATC, and before making hourly firm 
service mandatory, the Commission should ensure that the rights of 
long-term firm customers will not be negatively affected.
---------------------------------------------------------------------------

    \310\ E.g., APPA, Northwestern, Powerex, Public Power Council, 
Salt River, and South Carolina E&G.
---------------------------------------------------------------------------

    337. Among commenters who oppose requiring the adoption of hourly 
firm service,\311\ many repeat arguments that appeared in Order No. 
888. For example, several commenters express concern that hourly firm 
service will lead to ``cream skimming,'' result in unfairness to 
longer-term firm transmission customers who would have to be curtailed 
pro rata along with customers who have only made hourly firm 
commitments, or create inefficiencies by having a higher reservation 
priority than subsequently submitted load-based services such as 
secondary network service.\312\ But other commenters who oppose 
requiring hourly firm service state that the concerns expressed in 
Order No. 888 may no longer be a major problem, and may be addressed by 
allowing hourly firm service to be pre-empted by longer term firm 
service requests.\313\
---------------------------------------------------------------------------

    \311\ E.g., Ameren, APS, Duke, EEI, KCP&L, LG&E, LPPC, 
MidAmerican, NRECA, Progress Energy, Snohomish, Southern, TAPS, TVA, 
TDU Systems, and WAPA.
    \312\ E.g., LG&E, Progress Energy, Southern, and TAPS.
    \313\ E.g., EEI and WAPA.
---------------------------------------------------------------------------

    338. TVA argues that reservations for hourly firm service would 
nearly always end up being bumped by requests for longer service and as 
such would waste valuable time and increase administrative costs with 
no real benefit.
Processing
    339. On the issue of whether a transmission customer should be 
permitted to batch requests for service, those in favor generally state 
that batching allows for greater efficiencies.\314\ For example, 
Bonneville states that batching in the hourly market would decrease the 
response time for all requests in the hourly queue. Salt River states 
that a potential customer should be able to submit a batch of requests 
(e.g., a block of hours) that is useful in shaping the service to its 
load-serving needs. Snohomish states that in the day-ahead schedule 
submittals, batching of hourly firm transmission requests for 
evaluation as a single request should be permitted, but for periods 
prior to day-ahead, batching of hourly requests should not be allowed 
due to the potential for ``cream skimming.''
---------------------------------------------------------------------------

    \314\ E.g., Alberta Intervenors, Bonneville, Constellation, 
EPSA, and South Carolina E&G.
---------------------------------------------------------------------------

    340. Among those opposed to or expressing reservations regarding 
batching, Ameren and EEI argue that transmission providers already have 
the ability to process multiple requests from the same party, but they 
caution that batching requests for simultaneous modeling purposes 
(e.g., transmission from points A to B and B to A simultaneously) would 
be difficult to implement. WAPA states that, in its experience, the 
majority of hourly firm transmission requests must be uniquely 
identified and evaluated for potential conflicts with longer-term firm 
transmission requests.
Scheduling
    341. The pro forma OATT currently requires that schedules for firm 
and non-firm service be submitted on different timelines. Schedules for 
hourly non-firm point-to-point service must be submitted to the 
transmission provider no later than 2 p.m. the day before service is to 
commence.\315\ For all firm services, schedules must be submitted to 
the transmission provider no later than 10 a.m. the day before service 
is to commence.\316\
---------------------------------------------------------------------------

    \315\ See pro forma OATT section 14.6 (also allowing schedules 
to be submitted by a reasonable time that is generally accepted in 
the region).
    \316\ See pro forma OATT section 13.8 (also allowing schedules 
to be submitted by a reasonable time that is generally accepted in 
the region).
---------------------------------------------------------------------------

    342. Some commenters argue that firm and non-firm hourly services 
should be subject to the same scheduling timeline.\317\ To do 
otherwise, Snohomish argues, would be administratively burdensome and 
without benefit to the transmission provider or transmission customer. 
Those arguing for different scheduling timelines generally argue that 
the scheduling time-frames for firm and non-firm transmission service 
should remain different, at least on a pre-schedule or day-ahead basis, 
because the transmission provider must know the full extent of firm 
utilization before non-firm offerings can be determined.\318\
---------------------------------------------------------------------------

    \317\ E.g., Ameren, Constellation, PNM-TNMP, Powerex, Salt 
River, Snohomish, and South Carolina E&G.
    \318\ E.g., Ameren, Northwestern, and Southern.
---------------------------------------------------------------------------

Discussion
    343. The Commission proposes to add point-to-point hourly firm 
service to the pro forma OATT because it will eliminate a barrier to 
the development of markets and thereby decrease opportunities for undue 
discrimination. The terms of service we propose will ensure that hourly 
firm customers are offered service in a manner consistent with 
comparability principles, and pay their fair share of system costs. We 
conclude that hoarding and speculation should not be a major concern 
because requests for hourly firm service are subject to preemption by 
longer-term requests for service. We also conclude that the provision 
of hourly firm should have no effect on investment in the grid because 
a transmission provider does not plan its system to meet hourly firm, 
or any other short-term firm, transmission requests. In addition, the 
expected effect of hourly firm on long-term transactions is no 
different than the effect of other short-term firm services. For 
example, though commenters are correct that hourly firm will be 
curtailed pro rata with longer term firm point-to-point service, this 
is already true of daily firm point-to-point service. As noted in the 
NOI, many transmission providers already offer this service and there 
appear to be no technical impediments to offering it, nor have 
customers on these systems

[[Page 32687]]

expressed any concern about the effect of hourly firm on long-term firm 
services or curtailments. Therefore, we conclude that the concerns 
expressed in Order No. 888 regarding unduly discriminatory effects of 
hourly firm service have proven unfounded, and we propose that hourly 
firm service be a required offering in the pro forma OATT.
    344. As for the pricing of hourly firm service, consistent with 
Commission precedent, we propose to use the ``IES Method'' and apply 
different pricing for hourly firm service based on whether the service 
is taken during peak or off-peak hours.\319\ Pricing for hourly firm 
service during peak periods would be based on 4,160 hours annually of 
peak usage over 52, 5-day weeks of 16-hour days (52 x 5 x 16 = 4,160), 
rather than all 8760 hours of the year. In other words, the rate is 
derived from the hours during which the facilities are likely to be 
used, rather than the total hours in the year. It is premised on the 
assumption that a customer using the transmission system for the 16 
peak hours of the day should pay the same contribution to fixed costs 
as a customer who has reserved capacity on a daily basis.\320\ But 
because hourly service is unlikely to be taken only during peak hours, 
we propose to allow pricing for hourly firm service for off-peak hours 
based on 8,760 hours of usage.\321\ This is appropriate because 
customers using short-term service during off-peak hours do not 
constrict the system during the peak period, and should pay less than 
what they pay during the peak period.\322\ To ensure that hourly 
customers do not pay more than their fair share of fixed costs, 
consistent with the pricing principles set forth in Order No. 888, the 
total charge in any day for hourly service cannot exceed the stated 
daily rate multiplied by the maximum hourly capacity reservation during 
such day.\323\ We conclude that using the IES Method to price hourly 
firm service at a higher rate during peak periods will ensure that 
hourly firm customers pay a fair share of the costs of the transmission 
system and, as a result, mitigate ``cream-skimming'' concerns.
---------------------------------------------------------------------------

    \319\ The Method is named for a proceeding in which peak and 
off-peak pricing was applied to hourly non-firm transmission 
service. IES Utilities, Inc., 81 FERC ] 61,187 at 61,833-34 (1997), 
reh'g denied, 82 FERC ] 61,089, aff'd on other grounds sub nom, 
Wisconsin Public Power Inc., v. FERC, 1999 U.S. App. LEXIS 3998 
(Feb. 23, 1999) (unpublished opinion); see New York State Electric & 
Gas Corp., 92 FERC ] 61,169 at 61,593-94(2000) (approving 
application of the IES Method for time-differentiated hourly non-
firm rate design), order on reh'g, 100 FERC ] 61,021 (2002).
    \320\ Peak period pricing is referred to as the ``Appalachian 
Method'' or ``AEP Method,'' and takes its name from the proceeding 
in which it originated. Appalachian Power Co., 30 FERC ] 61,296 
(1987). The Appalachian Method is consistent with the premise that 
firm transmission service be priced based on the system's peak 
periods of usage. See Entergy Services, Inc. 85 FERC ] 61,163, at 
61,645 (1998) (approving application of the method for firm service 
on an hourly basis during peak hours), reh'g denied, 91 FERC ] 
61,153 (2000).
    \321\ See IES Utilities, Inc., 81 FERC at 61,833-34 (approving 
use of an 8,760 hour year to calculate rates for non-firm service on 
an hourly basis during off-peak hours); Entergy Services, Inc., 85 
FERC at 61,645 (approving use of an 8,760 hour year to calculate 
rates for firm service on an hourly basis during off-peak hours).
    \322\ Appalachian Power Co., 39 FERC at 61,965; see American 
Electric Power Service Corp., 88 FERC ] 61,141 at 61,453-54 (1999).
    \323\ And, in turn, the total demand charge in any week pursuant 
to a reservation for hourly or daily service cannot exceed the 
weekly rate multiplied by the maximum hourly capacity reservation in 
any hour during such week. See pro forma OATT schedules 7 and 8; see 
also Entergy Services, Inc., 85 FERC ]61,163 at 61,645 (1998) 
(applying these principles to a proposal for firm service on an 
hourly basis), reh'g denied, 91 FERC ]61,153 (2000).
---------------------------------------------------------------------------

    345. As for allowing transmission customers to batch requests for 
service, we conclude that allowing such batching creates administrative 
efficiencies for the transmission customer and transmission provider 
alike. Therefore, we propose allowing transmission customers to batch 
requests and schedules for hourly firm service that will be provided 
within the same day.
    346. The Commission also concludes that the current scheduling 
practices can accommodate the scheduling of hourly firm transmission 
service. To require that both firm and non-firm hourly services be 
scheduled at the same time would require that the existing procedures 
be revised, with no discernible benefit to the transmission customer or 
transmission provider. Even with the addition of this new service, it 
remains reasonable to require that the transmission provider have all 
firm schedules at the same time, and in advance of the deadline for 
non-firm schedules. Therefore, we propose that schedules for firm 
hourly service, like all other firm schedules, will be due by 10 a.m. 
the day before the service is to commence.
    347. Finally, we propose that, consistent with other durations of 
service, the confirmation period for hourly firm service specified in 
section 13.2 of the pro forma OATT will allow longer-term requests for 
service to preempt shorter hourly firm requests for service until one 
hour before the commencement of hourly firm service.
3. Rollover Rights
    348. Section 2.2 of the pro forma OATT allows existing firm 
transmission service customers--wholesale requirements and 
transmission-only customers with contracts of one year or more--the 
right to continue to take transmission service from the transmission 
provider when the customer's contract expires, rolls over or is 
renewed. The pro forma OATT provides that the 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 from another supplier. This transmission 
reservation priority for existing firm transmission service customers, 
which is also referred to as a right of first refusal or a rollover 
right, is an ongoing right that may be exercised at the end of all firm 
contract terms of one year or longer. A transmission customer must give 
notice of whether it will exercise its right of first refusal 60 days 
before the expiration of its service agreement.
    349. In Order No. 888, the Commission provided that, if a 
transmission customer subject to the rollover right selects a new power 
supplier that substantially changes the location or direction of its 
power flows, the customer's right to continue taking service from the 
transmission provider may be affected by transmission constraints 
associated with the change.\324\ The Commission also provided that a 
transmission provider may reserve existing capacity for retail native 
load and network load growth reasonably forecasted within the 
transmission provider's current planning horizon, but that any capacity 
so reserved must be posted on the transmission provider's OASIS and 
made available to others until the capacity is needed for the 
anticipated network or retail native load use.\325\ The Commission also 
has held that a transmission provider may restrict a right of first 
refusal based on pre-existing contracts that commence in the future if 
the transmission provider knows at the time of the execution of the 
original service agreement that ATC used to serve a customer will be 
available for only a particular time period, after which time it is 
already committed to another transmission customer under a previously 
confirmed transmission request.\326\ Once a

[[Page 32688]]

transmission provider evaluates the impact on its system of serving a 
long-term firm transmission customer and grants the transmission 
customer existing capacity, the transmission provider must plan and 
operate its system with the expectation that it will continue to 
provide service to the transmission customer should the transmission 
customer exercise the right of first refusal. If constraints arise 
after a transmission provider enters into a long-term agreement with 
the transmission customer (and that agreement does not contain an 
allowed restriction on the transmission customer's right of first 
refusal), the obligation is on the transmission provider to determine 
whether or not to build additional facilities to accommodate new 
transmission customers.\327\ A transmission provider is obligated to 
curtail service pursuant to its OATT or expand its system when its 
system becomes constrained such that it cannot satisfy existing 
transmission customers, including the exercise of their rollover 
rights, because it should have planned and operated its system with the 
expectation that each long-term firm transmission customer will 
exercise its rollover rights.\328\
---------------------------------------------------------------------------

    \324\ Order No. 888 at 31,665 n.176.
    \325\ Id. at 31,694.
    \326\ E.g., Southwest Power Pool, Inc., 109 FERC ] 61,041 at P 6 
(2004).
    \327\ Id. at P 9.
    \328\ Id.
---------------------------------------------------------------------------

    350. If a transmission provider's transmission system cannot 
accommodate all of the requests for transmission service at the end of 
the contract term, the existing long-term transmission customer must 
agree to match the rate offered by the potential customer, up to the 
transmission provider's maximum rate, and to accept a contract term at 
least as long as that offered by the potential customer. However, a 
competitor's offer does not have to be ``substantially similar in all 
respects'' to the existing transmission customer's.\329\
---------------------------------------------------------------------------

    \329\ Idaho Power Co. v. FERC, 312 F.3d 454, 462 (D.C. Cir. 
2002).
---------------------------------------------------------------------------

The NOI
    351. In the NOI, the Commission sought comment on whether 
transmission providers have hindered transmission customers under pre-
Order No. 888 agreements from rolling over their contracts that allow 
purchase of capacity and energy from another supplier. The Commission 
also asked whether the language in section 2.2 of the pro forma OATT 
needs to be reformed to ensure that rollover rights are provided when 
transmission customers are seeking access to alternative supply 
sources, or whether the issue was an enforcement matter. The Commission 
sought comment on whether the rollover right policy determinations made 
subsequent to Order No. 888 should be included in the pro forma OATT. 
The Commission inquired whether there were other problems with section 
2.2, either as written or as implemented by transmission providers, 
that need to be addressed. The Commission also asked whether potential 
transmission customers are denied transmission access by the exercise 
of rollover rights. Finally, the Commission asked whether it should 
reconsider the concept of rollover rights and whether the one-year 
service with rollover rights is consistent with the need to create 
incentives for transmission investment or should a longer minimum term 
of service be adopted to qualify for rollover rights.\330\
---------------------------------------------------------------------------

    \330\ NOI at P 18.
---------------------------------------------------------------------------

Comments
    352. Many transmission providers and APPA argue that, because a 
transmission provider may not know until 60 days prior to termination 
whether a contract would be renewed, rollover rights in contracts as 
short as one year inhibit the ability of transmission providers to plan 
their systems.\331\ Transmission providers also argue that the right of 
first refusal results in the denial of transmission that leads to an 
inefficient use of transmission capacity.\332\ They explain that the 
transmission provider must hold back capacity from the market for 
existing transmission customers that have a right of first refusal but 
that have not yet indicated whether they intend to exercise it. By the 
time the termination notice is given, other transmission customers that 
may have wanted to reserve the newly freed capacity have been turned 
away and have made other arrangements. They assert that the result is 
an inefficient use of capacity. In addition, these transmission 
providers argue that the 60-day notice provision does not allow them 
adequate time to re-market any capacity when it is freed-up by the 
terminating customer. Further, certain transmission providers argue 
that the right of first refusal unfairly gives transmission customers a 
valuable ``free call option'' on transmission capacity without any 
obligation to take the capacity at the end of the contract or to 
compensate the transmission provider for the value of the option.\333\ 
To avoid these problems, many transmission providers suggest that the 
rollover right should apply to firm transmission contracts with minimum 
terms of between two and ten years.\334\ In addition, these commenters 
suggest that, if the Commission lengthens the term of the firm 
contracts eligible for the right of first refusal, the 60-day renewal 
provision also should be extended.
---------------------------------------------------------------------------

    \331\ E.g., APPA, Bonneville, Duke, LPPC, Nevada Companies, 
Progress, and Salt River.
    \332\ E.g., Ameren, Duke, EEI, North Carolina Commission, Santa 
Clara, and South Carolina E&G.
    \333\ E.g., Ameren, Entergy, and Nevada Companies.
    \334\ E.g., APPA, Bonneville, Cinergy, LDWP, MidAmerican, Nevada 
Companies, Progress, Santee Cooper, South Carolina E&G, and 
Southern.
---------------------------------------------------------------------------

    353. Certain transmission customers argue that the Commission 
should retain the right of first refusal in its present form, or change 
it only after the Commission requires regional planning or other events 
occur.\335\ Transmission customers stress the need for the rollover 
rule as a means to ensure long-term service. According to 
Constellation, transmission customers subject to rollover rights are 
not temporary customers but are long-term customers that happen to take 
their service under year-to-year agreements. Likewise, EPSA asserts 
that rollover rights are important in planning for the long-term needs 
of loads and generation located on the grid and that ``the ability to 
roll over a firm transportation contract (by matching the contract term 
and the rate of competing shippers) is the only way that market 
participants can ensure that their needs will be met.''
---------------------------------------------------------------------------

    \335\ E.g., AMP-Ohio, Calpine, Constellation, and EPSA.
---------------------------------------------------------------------------

    354. Numerous commenters address the impact of native load growth 
on the right of first refusal rule. As previously indicated, the 
Commission permits transmission providers to restrict a firm 
transmission customer's right of first refusal based on the 
transmission provider's reasonable projections of native load growth. 
Several commenters argue, however, that the Commission has not provided 
adequate guidance as to the information a transmission provider must 
submit to demonstrate native load growth.\336\ Further, commenters 
argue that the Commission should allow transmission providers a means 
to update their native load data to address any load growth that was 
not anticipated at the time of the original contract. In addition, some 
commenters argue that the Commission's rejection of native load growth 
projections in prior cases, and the provision for pro rata curtailment 
of service in the event of capacity shortfalls due to the exercise of a 
right of first refusal, fail to respect the native load preference 
adopted in Order No. 888, as well as in section 217 of the FPA as added 
by section 1233 of EPAct

[[Page 32689]]

2005. They argue that new section 217 of the FPA reverses Commission 
precedent that limits the ability of transmission providers to recall 
capacity for native load once it is subject to a right of first 
refusal.
---------------------------------------------------------------------------

    \336\ E.g., Duke, EEI, Entergy, Nevada Companies, Progress 
Energy, Santee Cooper, and Salt River.
---------------------------------------------------------------------------

Discussion
    355. The comments filed in response to the NOI demonstrate a need 
to retain, but revise, the right of first refusal provision in the pro 
forma OATT. The Commission proposes to revise the right of first 
refusal provision in the pro forma OATT to apply to wholesale 
requirements and transmission-only contracts that have a minimum term 
of five years, rather than the current minimum term of one year. In 
addition, the Commission proposes that a transmission customer under a 
rollover agreement must provide notice of whether or not it will 
exercise its right of first refusal no less than one year prior to the 
expiration date of the transmission service agreement. We agree with 
APPA that these changes strike an appropriate balance between providing 
customers meaningful rollover rights and encouraging long-term 
contracting, new investment and long-term planning. Finally, if the 
existing customer seeks to exercise its rollover right and there is 
insufficient transmission capacity on the system at the end of the 
contract term to accommodate all of the requests for transmission 
service, the existing customer would have to agree to accept a contract 
term at least equal to a competing request by any new customer or five 
years, whichever is longer, and to pay the current just and reasonable 
rate, as approved by the Commission, for such service.
    356. The Commission's proposal is consistent with the transmission 
customers' comments that the right of first refusal should be designed 
to ensure long-term service. Extending the minimum term of the right of 
first refusal agreements to five years will encourage long-term use of 
the grid. In addition, the one-year prior notice requirement should 
allow adequate time for transmission providers to re-market unused 
capacity that may result from a transmission customer choosing not to 
roll over a service agreement. The one-year notice provision also 
should limit the instances when the transmission provider must turn 
away a transmission request only to find out that it could accommodate 
the request after the transmission customer elected not to roll over. 
These changes should result in a more efficient use of the transmission 
grid.
    357. If we adopt the proposed minimum five year/one year right of 
first refusal provision in the pro forma OATT, we propose to allow this 
provision to become effective upon Commission acceptance of the 
transmission provider's coordinated and regional planning process set 
forth in Attachment K of its OATTs. Thus, all new transmission service 
agreements executed after the effective date of Attachment K will be 
subject to the five year/one year right of first refusal rule. The 
Commission proposes that transmission service agreements subject to a 
right of first refusal entered into prior to the effective date of 
revised section 2.2, unless terminated, will become subject to the five 
year/one year right of first refusal rule on the first rollover date 
after the effective date of revised section 2.2.
    358. Our existing policy allows the transmission provider to limit 
a transmission customer's right of first refusal by reserving capacity 
to accommodate reasonably forecasted and verifiable native and network 
load growth at the time the initial service agreement is executed. Many 
transmission providers argue that this right should be extended to 
allow the transmission provider to limit the right of first refusal 
each time the right of first refusal is exercised, not only at the time 
the initial service agreement is executed. We believe that our proposal 
to extend the term of the right of first refusal from one to five years 
should address, in many respects, the concern of transmission providers 
that the existing right of first refusal is unfair to native load 
customers. Under this proposal, a right of first refusal will no longer 
be granted to users of the grid on an annual basis, but rather only to 
those making longer-term commitments to the grid, as do native load 
customers. In addition, while we expect a transmission provider to be 
continually updating its forecast for native load growth and applying 
this updated projection to new requests for service, applying this to 
contracts at rollover may require an additional change to the right of 
first refusal process. Specifically, the transmission provider would 
have to compete for the capacity rather than reclaim it through its 
rights to reserve capacity for native load growth. We seek comment on 
whether this change would be appropriate. Further, while we have 
addressed requests to limit the right of first refusal on the basis of 
native load growth on a case-by-case basis, we recognize that this 
approach has not yet resulted in a clear and transparent method for 
demonstrating forecasted native load growth. Accordingly, we seek 
comment on whether there is a sufficiently clear, consistent, and 
transparent method that could be implemented on a generic basis to 
address the need for a transmission provider to demonstrate its 
forecast of native load growth and its effect on capacity reserved by 
right of first refusal customers.
    359. Many transmission providers argue that our current right of 
first refusal policy is inconsistent with the native load protections 
contained in section 217(b) of the FPA. We disagree, but note that the 
reforms being proposed here should moot this argument. We are proposing 
to extend the minimum term of the right of first refusal to a period 
(five years) that is more consistent with the planning horizons of 
transmission providers. In addition, limiting the right of first 
refusal to agreements with terms of five years or more will ensure that 
the right of first refusal is used by customers with long-term 
obligations to purchase capacity rather than as a means for customers 
with shorter-term transactions to use capacity for non-load-serving-
entity transactions.\337\ This is consistent with FPA section 
217(b)(4), which states that the Commission shall 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 the service obligations of the load-serving 
entities.'' Our proposal also is consistent with FPA section 217(b)(2) 
because it continues to allow the transmission provider to limit the 
right of first refusal to accommodate reasonably forecasted and 
verifiable native load growth.
    360. Under the proposed rule, transmission providers still will be 
required to plan their systems with the expectation that a transmission

[[Page 32690]]

customer with a long-term transmission agreement subject to a right of 
first refusal will exercise its rollover right at the end of its term. 
We believe it is important to reiterate the obligation on transmission 
providers to maintain ATC for existing transmission customers with 
rollover rights and our expectation that transmission providers will 
include all customers with rollover rights in their long-term 
planning.\338\ We understand that some existing reliability procedures 
or practices may encourage transmission providers to exclude certain 
transmission service contracts from their base-case models, even if 
those contracts contain a rollover right. This is inconsistent with 
Commission policy and undermines the purpose of the rollover right, 
which is to facilitate system planning and reliability.
4. Modification of Receipt or Delivery Points
    361. Section 22 of the pro forma OATT provides that a transmission 
customer taking firm point-to-point service may modify its receipt and 
delivery points on either a non-firm or a firm basis. Section 22.1 
(Modifications on a Non-Firm Basis) provides that, subject to certain 
conditions, a firm point-to-point customer may request transmission 
service on a non-firm basis over receipt and delivery points other than 
those specified in its service agreement (known as secondary receipt 
and delivery points) in amounts not to exceed its firm capacity 
reservation, without incurring an additional non-firm point-to-point 
service charge or executing a new service agreement. Section 22.2 
(Modifications on a Firm Basis) provides that any request to modify 
receipt and delivery points on a firm basis shall be treated as a new 
request for service in accordance with section 17 of the pro forma OATT 
(Procedures for Arranging Firm Point-to-Point Transmission Service), 
except that the 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 retains its priority for 
service at the existing firm receipt and delivery points specified in 
its service agreement.
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    \337\ This is consistent with the approach suggested by TAPS, 
which argues that the current one-year minimum contract term allows 
significant capacity on constrained interfaces to be tied up in 
relatively short-term deals simply designed to hold the firm 
reservation as a path for non-firm economy purchases and to block 
competitors' firm access (e.g., inexpensive, one-year ``paper 
capacity'' deals). TAPS also argues that any restriction on the 
availability and flexibility of rollover rights be contingent on an 
expansion of the transmission grid so that transmission customers 
have reasonable access to competitive supplies. We agree that 
expansion of the grid is critical and accordingly have proposed to 
require coordinated transmission planning on both a local and 
regional level to ensure that transmission customers' needs are 
treated comparably to those of the transmission provider. This 
enhanced transmission planning, combined with other reforms proposed 
in this NOPR (e.g., improvements to the calculation of ATC), should 
mitigate TAPS's concerns by improving the ability to access 
competitive supplies.
    \338\ See, e.g., Southern Company Services, Inc., 104 FERC ] 
61,140 at P 26-27 (2003).
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    362. In the NOI, the Commission asked whether transmission 
customers have experienced undue discrimination in attempting to 
redirect to new receipt and delivery points pursuant to section 22.2 
and whether any reforms were needed. The Commission did not 
specifically ask about section 22.1, but some commenters nevertheless 
addressed this section. Most commenters, however, did not distinguish 
whether they were concerned with firm or non-firm redirects and instead 
addressed redirects generally.
Comments
    363. APPA notes that many of its members have experienced 
difficulties in changing receipt points, especially when such requests 
involve new sources of supply. In many cases, APPA asserts that 
transmission providers require major upgrades before they will grant a 
redirect to new points. The Public Power Council points out that 
redirecting to new points depends on ATC, and, therefore, the ability 
to make changes would be improved by better public knowledge of ATC at 
those points in all timeframes and by more information about ATC 
calculation methodologies. EPSA asserts that difficulty in redirecting 
to new points inhibits the ability to reassign capacity. Williams 
complains about delays by transmission providers in answering requests 
for redirects and urges the Commission to enforce OATT procedures and 
to consider a ``fast-track'' process for reviewing requests to 
redirect.
    364. Bonneville and EEI believe that any discrimination may be an 
unintentional result of a lack of clarity in the pro forma OATT, and 
are joined by MidAmerican, Progress Energy, and PNM-TNMP in calling for 
a number of clarifications. MidAmerican believes that these 
clarifications will provide flexibility to transmission customers and 
will enhance the ability to reassign transmission service to customers 
desiring different points of receipt or delivery.
    365. Southern and Ameren assert that because customers often make 
redirect requests at the last minute, there is often not enough time 
for the market to respond to capacity made available on an abandoned 
path. Southern also highlights the administrative burdens and 
complexity (particularly for reliability) of processing short-term 
changes in service and suggests that the Commission consider measures 
to encourage transmission customers to provide greater certainty as to 
the expected paths along which they will schedule service and to do so 
in a more timely manner. Southern, along with Bonneville, also urges 
the Commission to clarify rollover rights when service is redirected to 
new points. In general, however, Southern believes that the 
Commission's current redirect policies are reasonable and practical.
    366. A number of commenters focus on other related transmission 
issues, such as the flexibility afforded network service versus point-
to-point service or other network-service-related issues; \339\ the 
lack of flexibility with point-to-point service generally; \340\ or 
issues associated with the interconnection of network load at new 
delivery points.\341\
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    \339\ E.g., Alberta Intervenors, Calpine, and TAPS.
    \340\ E.g., Occidental.
    \341\ E.g., NRECA and TDU Systems.
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Discussion
    367. The Commission believes that it has already addressed many of 
the concerns raised by commenters with regard to reform of section 22 
of the pro forma OATT in Docket No. RM05-5-000.\342\ 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).\343\ Order No. 676 incorporates the 
aforementioned standards by reference into the Commission's 
regulations; requires public utilities to implement the standards by 
July 1, 2006; and requires public utilities to file revisions to their 
OATTs to include these standards.\344\ The WEQ Standards recently 
adopted by the Commission include a number of standards addressing 
requirements for dealing with redirects on both a firm and non-firm 
basis.\345\ In fact, all of the WEQ Standards dealing with redirects 
were adopted by the Commission in Order No. 676, except for WEQ 
Standard 001-9.7, which addresses the impact of a firm redirect on a 
long-term firm transmission customer's rollover rights under section 
2.2 of the pro forma OATT. The Commission directed the WEQ to 
reconsider WEQ Standard 001-9.7 and to adopt a revised standard 
consistent with the Commission's

[[Page 32691]]

policies.\346\ The Commission also offered guidance to assist the WEQ 
in developing a standard that is consistent with Commission 
policy.\347\
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    \342\ 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).
    \343\ The WEQ was established by NAESB in response to a 
Commission order requesting the wholesale electric power industry to 
develop business practice standards and communication protocols by 
establishing a single consensus, industry-wide standards 
organization for the wholesale electric industry. See id. at P 3-4.
    \344\ The standards will hereinafter be referred to as the WEQ 
Standards. The Commission proposes to add a reference to the WEQ 
standards in section 4 of the pro forma OATT, which identifies the 
Commission's regulations containing the terms and conditions 
relevant to the OASIS and standards of conduct.
    \345\ The requirements for dealing with redirects on a firm 
basis are found at WEQ Standard 001-9, et seq., and the requirements 
for dealing with redirects on a non-firm basis are found at 001-10, 
et seq.
    \346\ Order No. 676 at P 52.
    \347\ Id. at P 53-61.
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    368. As noted above, we believe that a number of concerns raised by 
commenters are addressed by the WEQ Standards. For example, we believe 
that the request of commenters for clarification that redirect service 
may be requested for only a portion of the original quantity of service 
is addressed for firm and non-firm service by WEQ Standards 001-9.2 and 
001-10.2, respectively, which provide that the transmission customer 
``shall be allowed to request a Redirect on a [Firm/Non-Firm] basis for 
a portion or all of the Capacity Available to Redirect.'' Likewise, the 
request of commenters for clarification that it is not necessary for a 
customer to redirect its service for the entire remaining term of 
service is addressed for firm and non-firm service by WEQ Standards 
001-9.3 and 001-10.3, respectively, which provide that the transmission 
customer ``shall be allowed to request a Redirect on a [Firm/Non-Firm] 
basis for a portion or all of the time period of the Parent 
Reservation.'' While we believe that many concerns expressed by 
commenters with regard to redirects in this proceeding have been 
addressed by Order No. 676, we request that each commenter reconsider 
its concerns in this area with the benefit of Order No. 676's adoption 
of the WEQ Standards, and inform us if additional concerns remain. The 
Commission notes that several of the most active commenters addressing 
redirects in this proceeding also were commenters in Docket No. RM05-5-
000 and therefore should be familiar with whether a particular WEQ 
Standard addresses the issues raised in the comments submitted in this 
proceeding.\348\
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    \348\ For example, Bonneville, EEI, NRECA, and Southern each 
commented in Docket No. RM05-5-000.
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    369. The Commission anticipates that a number of other concerns, 
while perhaps not yet addressed (or addressed fully) by a WEQ Standard, 
are nevertheless the types of issues appropriate for the WEQ process. 
The Commission therefore proposes that each commenter that continues to 
believe additional reform is necessary in this area also evaluate 
whether its concerns would more appropriately be addressed by the WEQ 
as it considers its next version of its standards.\349\ Specifically, 
as noted above, the WEQ is in the process of reevaluating WEQ Standard 
001-9.7, dealing with redirects and rollovers, so that it is consistent 
with the Commission's guidance given in Order No. 676. The Commission 
requests comment on whether the WEQ process, along with the guidance 
provided by the Commission in Order No. 676, is sufficient to address 
the concerns of commenters that seek clarification on the interplay 
between redirects and rollovers.
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    \349\ The Commission notes in this regard that the WEQ's 
procedures ensure that all industry members can have input into the 
development of a business practice standard, whether or not they are 
members of NAESB, and each standard it adopts is supported by a 
consensus of the five industry segments: Transmission, generation, 
marketers/brokers, distribution/load-serving entities, and end-
users. See Order No. 676 at P 5 & n.5.
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    370. The Commission understands, however, that there are also more 
fundamental concerns with regard to section 22 that were raised in the 
NOI. Many comments reflect concerns about the inability of transmission 
customers to effectively redirect their transmission service to new 
receipt and delivery points in order to accommodate a new transaction, 
the reassignment of capacity, or the designation of a new supply 
source. Generally, these commenters argue that their ability to 
redirect to new points is stymied by a lack of ATC at the new points or 
the need for major upgrades at the new points; or that the transmission 
provider takes too long to process its redirect request. Transmission 
providers, on the other hand, complain of the administrative burdens 
and complexity (particularly with regard to reliability) of processing 
transmission customers' short-term changes in service, and also assert 
that there is often not enough time for the market to respond to 
capacity made available on customers' original paths.
    371. The ability to redirect to new points is a function of whether 
there is ATC at the new points. The Commission believes that its 
proposed reforms requiring coordinated transmission planning between 
transmission providers and their customers, as well as regional 
transmission planning open to all stakeholders, will lead to a more 
rationally planned transmission system that will result in fewer 
transmission constraints and more ATC available to accommodate requests 
to redirect to new points.\350\ Additionally, the Commission's proposed 
reforms regarding the calculation of ATC and increased transparency 
over the process will engender increased confidence among transmission 
customers in their transmission providers' ATC postings.\351\ In short, 
transmission customers will have more accurate and complete ATC 
information to utilize in evaluating their redirect options. Moreover, 
through increased transparency, transmission customers will have the 
information they need to question a transmission provider's denial of a 
request to redirect. Thus, we believe that our reforms in the area of 
transmission planning and ATC calculation should go a long way toward 
addressing transmission customer concerns in this area. Should 
commenters believe that our proposed reforms in this area will not 
address their concerns effectively, or that there is a better way of 
addressing them, we encourage them to submit a specific proposal, along 
with proposed revised pro forma OATT language.
---------------------------------------------------------------------------

    \350\ Supra Part V.B.
    \351\ Supra Part V.A.
---------------------------------------------------------------------------

    372. We believe that redirects should be as customer-friendly as 
possible. Other pro forma OATT reforms proposed in this rulemaking 
should improve the ability to redirect transmission service to new 
points pursuant to section 22. For example, the modifications to firm 
point-to-point service discussed above will be applicable to a request 
to redirect on a firm basis, as such requests are treated as a new 
request for service under pro forma OATT section 22.2. In addition, 
reforms related to the acquisition of service discussed below (e.g., 
with regard to making and processing requests for service, queuing, and 
reservation priority) should, among other things, help to address 
transmission customer concerns that transmission providers are too slow 
in processing redirect requests. These reforms also should help to 
address transmission provider concerns that customers do not respond 
completely and in a timely manner and that there is insufficient time 
to re-market capacity on the original paths.
5. Acquisition of Transmission Service
a. Processing of Service Requests
    373. The pro forma OATT includes requirements that transmission 
providers process requests for transmission service in a timely 
fashion. Section 17.5 (Response to a Completed Application) and section 
18.4 (Determination of Available Transmission Capability) of the pro 
forma OATT provide that following the receipt of a completed 
application for service, the transmission provider must respond to 
transmission customer requests for determinations of the availability 
of firm and non-firm

[[Page 32692]]

transmission capacity on a timely basis. The transmission provider must 
make the determination as soon as reasonably practicable after receipt 
but no later than certain specified time periods (or such time periods 
generally accepted in the region). Section 19 (Additional Study 
Procedures for Firm Point-to-Point Transmission Service Requests) of 
the pro forma OATT provides deadlines that transmission providers must 
adhere to in issuing system impact study agreements and facilities 
studies agreements and that transmission customers must abide by in 
responding to these study agreements. Section 19 requires transmission 
providers to use due diligence to complete system impact studies and 
facilities studies within 60 days. Section 32 of the pro forma OATT 
(Additional Study Procedures for Network Integration Transmission 
Service Requests) contains similar due diligence deadlines for 
completing system impact studies and facilities studies associated with 
requests for network service.
    374. In the NOI, the Commission sought comment on problems 
transmission customers and transmission providers have experienced 
regarding the timely processing of requests for transmission service. 
In particular, the Commission sought comment regarding whether 
transmission customers have experienced delays by transmission 
providers in responding to requests for transmission service in general 
and, in particular, what problems commenters have experienced as 
transmission providers process the queue for requests for transmission 
service that cannot be immediately granted due to a lack of ATC. We 
also asked about the type of remedies the Commission should impose on 
public utility transmission providers for missing deadlines set forth 
in their OATTs. Another issue we sought comment on was whether 
commenters have identified blocking issues, such as where a customer 
submits multiple requests intending to proceed with a single request 
specifically to keep others out of the queue; and if so, whether 
allowing transmission providers to charge a processing fee would reduce 
the incentive to submit multiple self-competing requests. Finally, we 
sought comment on whether the Commission should require transmission 
providers to study transmission requests as a group.
Comments
    375. A number of merchant generators articulated general concerns 
regarding the time it takes transmission providers to process requests 
for transmission service.\352\ EPSA notes that timeliness in responding 
to transmission requests is a consistent problem. Constellation states 
that the untimely processing of requests for transmission service is a 
persistent problem under the OATT, particularly with respect to long-
term point-to-point service, network service, and modification of 
network resource designations. Arkansas Cities adds that, under the 
current OATT, utilities' lenient application of time periods needed for 
the system impact study process and facilities study process cause 
transmission customers to endure significant amounts of time to obtain 
confirmed firm delivery service at a reasonable cost.
---------------------------------------------------------------------------

    \352\ E.g., Constellation, EPSA, Powerex, and Williams.
---------------------------------------------------------------------------

    376. A number of commenters suggest that transmission providers 
should inform the Commission when they miss the target deadlines for 
completing system impact studies and facilities studies and/or post 
performance statistics on their OASIS sites that detail the time it 
takes them to process system impact studies and facilities 
studies.\353\ EPSA states that it strongly believes that the new OATT 
should require the transmission provider to notify the Commission when 
it is not able to meet deadlines. TDU Systems suggests that one way to 
address the difficulty of determining acceptable delays is to require 
transmission providers to post statistics on their OASIS sites 
providing information as to the length of time it might take to process 
requests for transmission service. Cinergy proposes that adopting 
specific reporting metrics that require transmission providers to 
report certain statistics regarding their performance could result in 
an improved quality of service.
---------------------------------------------------------------------------

    \353\ E.g., Cinergy, Constellation, EPSA, MidAmerican, Powerex, 
and TDU Systems.
---------------------------------------------------------------------------

    377. A number of merchant generators propose that the Commission 
assess operational penalties on transmission providers that fail to 
meet the study deadlines detailed in the pro forma OATT.\354\ LG&E 
recommends that the Commission consistently enforce the established 
deadlines through penalties or other remedies unless good cause for 
failure to comply can be shown, so as to promote nondiscriminatory 
adherence to established deadlines. Powerex suggests that the 
Commission: (a) Identify a threshold percentage rate of acceptable 
compliance with response timelines, (b) require transmission providers 
to monitor and post their own rates of compliance with Commission-
required timelines on a path-specific basis, as well as the reasons for 
delays, (c) require transmission providers whose rate of compliance on 
a particular path falls below the Commission's threshold to file a 
compliance report with the Commission identifying the problem(s) and 
corrective measures that will be undertaken (including a timeline for 
implementation of the corrective measures), and (d) use a progressive 
penalty system that begins with reporting and auditing requirements for 
non-compliant transmission providers and then moves toward monetary 
penalties in cases where a transmission provider exhibits a pattern of 
uncorrected noncompliance, as well as in any case where actual bad 
faith, discrimination or preferential treatment has occurred.
---------------------------------------------------------------------------

    \354\ E.g., EPSA, Powerex, and Williams.
---------------------------------------------------------------------------

    378. A number of transmission providers state that transmission 
service request processing is slowed by excessive requests for 
transmission service from the same transmission customer with 
essentially the same service attributes (e.g., point of receipt, point 
of delivery, start time, end time, firmness).\355\ A number of other 
commenters also argue that some transmission customers submit multiple 
requests for transmission service with no intent to confirm most of the 
requests if and when the requests are accepted.\356\ MidAmerican states 
that it is aware of cases where customers have submitted multiple 
requests for service associated with a new generator where the location 
of the new generator is not known but queue priority is being sought by 
the transmission customer. MidAmerican adds that the submission of such 
multiple requests for service affects the processing of other lower 
queued transmission requests. South Carolina E&G states that there are 
instances when a transmission customer submits multiple requests 
intending to proceed with a single request, seemingly with the purpose 
of keeping others out of the queue. AWEA states that transmission 
queues are frequently jammed with many projects holding each other up. 
AWEA asserts that there often are ``zombie'' projects blocking the 
queue, without a power purchase agreement or other indication that they 
are serious projects. Suez Energy NA responds that there are blocking 
issues when a transmission customer submits multiple requests for 
transmission

[[Page 32693]]

service but intends to proceed with a single request.
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    \355\ E.g., MidAmerican, Progress Energy, South Carolina E&G, 
and Southern.
    \356\ E.g., Alberta Intervenors, AWEA, Public Power Council, and 
Suez Energy NA.
---------------------------------------------------------------------------

    379. Several federal power agencies suggest that charging a fee on 
transmission service requests could provide the right incentive to 
transmission customers to limit requests for transmission service to 
only those requests they expect to confirm.\357\ Several other 
commenters suggest a similar fee.\358\ Bonneville supports the 
imposition of a processing fee for multiple requests to provide a 
disincentive to blocking behavior. Bonneville suggests that the fee 
should provide a disincentive for making multiple, ``self-competing'' 
requests. Bonneville suggests that, at a minimum, requests with the 
same point of receipt, point of delivery, source, sink, and time-frame 
should be considered ``self-competing.'' In addition, Bonneville 
contends that transmission providers should be allowed to define 
parameters to identify additional instances of ``self-competing'' 
requests on their systems. South Carolina E&G argues that there is 
merit to the concept of charging a processing fee that would increase 
with the duration of the requested service, to reduce the incentive to 
submit multiple self-competing requests.
---------------------------------------------------------------------------

    \357\ E.g., Bonneville and TVA.
    \358\ E.g., Alberta Intervenors, Snohomish, and South Carolina 
E&G.
---------------------------------------------------------------------------

    380. The majority of commenters were in favor of allowing, but not 
requiring, transmission providers to study requests for transmission 
service as a group, also known as clustering requests for transmission 
service.\359\ APPA and Bonneville suggest amending the pro forma OATT 
so that all requests received during a set time period are studied 
together. EEI argues that the Commission should not require the 
studying of transmission requests as a group, though transmission 
providers should continue to have the discretion to cluster 
transmission requests when it is efficient to do so. EPSA states that 
clustering should not be required, but may be considered as a customer 
option as part of a comprehensive planning process.
---------------------------------------------------------------------------

    \359\ E.g., EEI, EPSA, Nevada Companies, PacifiCorp, PNM-TNMP, 
Powerex, and Southern.
---------------------------------------------------------------------------

    381. Bonneville suggests that the Commission adopt two NAESB 
proposed business standards designed to reduce the number of self-
competing requests. In particular, Bonneville believes the Commission 
should adopt NAESB's proposed queue hoarding business practice and 
queue flooding business practice.
Discussion
    382. We agree with commenters who argue that requiring transmission 
providers to report the length of time they take to complete studies 
pursuant to sections 19 and 32 of the pro forma OATT would increase 
transparency and improve the ability of transmission customers and the 
Commission to detect undue discrimination. Therefore, we propose to 
require transmission providers to post on their OASIS sites metrics 
that track their performance in processing system impact studies and 
facilities studies associated with requests for transmission service. 
Transmission providers will be required to post the performance 
metrics, outlined below, for each calendar quarter. Transmission 
providers should begin tracking their performance upon the effective 
date of the final rule in this proceeding and keep the quarterly 
performance metrics posted on their OASIS sites for three calendar 
years. The transmission provider will be required to post the quarterly 
performance metrics within 15 days of the end of the quarter. The 
performance metrics outlined below should be calculated separately for 
affiliates' and non-affiliates' requests for short-term and long-term 
transmission service. A transmission provider also will be required to 
post performance metrics for studies that it conducts for RTOs.
    383. We propose to require transmission providers to post the 
following set of performance metrics on a quarterly basis:
     Process Time from Initial Service Request to Offer of 
System Impact Study Agreement pursuant to Sections 17.5, 19.1 and 32.1 
of the pro forma OATT
    [cir] Number of new System Impact Study Agreements delivered to 
Transmission Customers
    [cir] Number of new System Impact Study Agreements delivered to the 
Transmission Customer more than 30 days after the Transmission Customer 
submitted its request
    [cir] Average time (days) from request submittal to change in 
request status
    [cir] Average time (days) from request submittal to delivery of 
System Impact Study Agreement
    [cir] Number of new System Impact Study Agreements executed
     System Impact Study Processing Time pursuant to Sections 
19.3 and 32.3 of the pro forma OATT
    [cir] Number of System Impact Studies completed
    [cir] Number of System Impact Studies completed more than 60 days 
after receipt of executed System Impact Study Agreement
    [cir] Average time (days) from receipt of executed System Impact 
Study Agreement to date when completed System Impact Study made 
available to the Transmission Customer
    [cir] Average cost of System Impact Studies completed during the 
period
     Service Requests Withdrawn from System Impact Study Queue
    [cir] Number of requests withdrawn from the System Impact Study 
queue
    [cir] Number of System Impact Studies withdrawn more than 60 days 
after receipt of executed System Impact Study Agreement
    [cir] Average time (days) from receipt of executed System Impact 
Study Agreement to date when request was withdrawn from the System 
Impact Study queue
     Process Time from Completed System Impact Study to Offer 
of Facilities Study pursuant to Sections 19.4 and 32.4 of the pro forma 
OATT
    [cir] Number of new Facilities Study Agreements delivered to 
Transmission Customers
    [cir] Number of new Facilities Study Agreements delivered to 
Transmission Customers more than 30 days after the completion of the 
System Impact Study
    [cir] Average time (days) from completion of System Impact Study to 
delivery of Facilities Study Agreement
    [cir] Number of new Facilities Study Agreements executed
     Facilities Study Processing Time pursuant to Sections 19.4 
and 32.4
    [cir] Number of Facilities Studies completed
    [cir] Number of Facilities Studies completed more than 60 days 
after receipt of executed Facilities Study Agreement
    [cir] Average time (days) from receipt of executed Facilities Study 
Agreement to date when completed Facilities Study made available to the 
Transmission Customer
    [cir] Average cost of Facilities Studies completed during the 
period
    [cir] Average cost of recommended upgrades for Facilities Studies 
completed during the period
     Service Requests Withdrawn from Facilities Study Queue
    [cir] Number of requests withdrawn from the Facilities Study queue
    [cir] Number of Facilities Studies withdrawn more than 60 days 
after receipt of executed Facilities Study Agreement
    [cir] Average time (days) from receipt of executed Facilities Study 
Agreement to date when request was withdrawn from the Facilities Study 
queue
    384. We also propose to impose operational penalties when 
transmission providers routinely fail to meet the 60-

[[Page 32694]]

day due diligence deadlines prescribed in sections 19.3, 19.4, 32.3 and 
32.4 of the pro forma OATT. We propose to require a transmission 
provider to file a notice with 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. For the purposes of calculating this 
notification trigger, the transmission provider should aggregate all 
system impact studies and facilities studies that it completes during 
the quarter for non-affiliates.\360\ 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. The transmission provider then will be subject 
to an operational penalty if the transmission provider continues to be 
out of compliance with the deadlines prescribed in the pro forma OATT 
for each of the two quarters following its notification filing. The 
transmission provider will be deemed to be out of compliance if it 
completes 10 percent or more of non-affiliates' system impact studies 
and facilities studies outside of the deadlines prescribed in the pro 
forma OATT. The operational penalty 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. For any system impact study or facilities study 
completed during that quarter and more than 60 days after the study 
agreement was executed, the penalty will equal $500 for each day the 
transmission provider takes to complete the 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. Because of their independence, 
we do not believe that RTOs have an incentive to neglect their 
obligation to process applications for service in a timely fashion. As 
a result, we propose that RTOs will not be subject to this penalty 
regime.
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    \360\ For instance, if the transmission provider completes 4 
non-affiliates' system impact studies during the quarter with 2 
completed more than 60 days after the system impact study agreement 
was executed and completes 2 non-affiliates' facilities studies 
during the quarter with none completed more than 60 days after the 
facilities study agreement was executed, then the transmission 
provider will be deemed to have completed 2 out of 6 (33 percent) 
studies outside of the deadlines in the pro forma OATT.
---------------------------------------------------------------------------

    385. In addition to the operational penalty described above, we 
propose to require transmission providers to post on their OASIS sites 
additional performance metrics after making a notification filing. 
Transmission providers will have to post these performance metrics 
until they process at least 90 percent of all system impact and 
facilities studies within 60 days after the study agreement has been 
executed. Starting the quarter following a notification filing, the 
transmission provider will be required to post: (1) The average, across 
completed system impact studies, of the employee-hours expended per 
completed system impact study; (2) the average, across completed 
facilities studies, of employee-hours expended per completed facilities 
study, (3) the number of employees devoted to processing system impact 
studies, and (4) the number of employees devoted to processing 
facilities studies. These additional performance metrics should be 
calculated separately for affiliates' and non-affiliates' requests for 
transmission service and for short-term and long-term transmission 
service.
    386. In addition to the operational penalties described above, we 
may order other remedial actions, consistent with the Enforcement 
Policy Statement. Any other remedial action will be determined on a 
case-by-case basis. The transmission provider will pay the operational 
penalty described above, consistent with the proposed rule discussed in 
Part V.C.4.b. The transmission provider cannot recover for ratemaking 
purposes any operational penalty it pays for failing to process 
transmission service studies on a timely basis.
    387. With respect to the problem of multiple, self-competing 
transmission service requests, we seek comment on a fee structure that 
could provide a disincentive for transmission customers to submit such 
duplicative requests without penalizing transmission customers that 
have legitimate requests for transmission service. We seek detailed 
recommendations, including any proposed tariff language, regarding the 
standards we would use to identify requests that would be subject to a 
fee. We also seek recommendations on the level of the fee that balances 
our policy goals to discourage requests for transmission service that 
the transmission customer does not intend to confirm while not 
discouraging legitimate requests for transmission service. Finally, we 
seek comment regarding the circumstances, if any, under which the 
processing fee would be refunded to or credited to the transmission 
customer.
    388. In Order No. 2003, we encouraged transmission providers to 
study interconnection requests in clusters.\361\ We likewise encourage 
transmission providers to study requests for transmission service in 
clusters, though we will not require transmission providers to cluster 
requests for transmission service for study purposes.\362\ As with 
interconnection requests, studying requests for transmission service in 
clusters allows the transmission provider to consider all requested 
uses of the transmission system at one time. We seek comment regarding 
whether transmission providers should be required to study requests for 
transmission service in a group if the transmission provider fails to 
complete studies on a timely basis; and, if so, we seek comment on the 
circumstances that should trigger such a requirement and the 
appropriate method of implementing the requirement. We further seek 
comment regarding whether transmission providers should be required to 
study requests for transmission service in a group if all the 
transmission customers in the group agree to cluster their requests. We 
also seek comment regarding how to select the requests that belong to a 
cluster so that transmission customers cannot ``cherry-pick'' clusters 
to avoid transmission system upgrade costs.
---------------------------------------------------------------------------

    \361\ Order No. 2003 at P 155.
    \362\ We note that we previously have allowed transmission 
providers to study requests for transmission service in a group. 
See, e.g., Southwest Power Pool, Inc., 110 FERC ] 61,028 at P 16 
(2005).
---------------------------------------------------------------------------

    389. In Order No. 676, we incorporated by reference a number of 
NAESB business practices, including the business standards on queue 
hoarding and queue flooding.\363\ NAESB's queue hoarding business 
practice allows transmission providers to deny a transmission 
customer's identical requests for transmission service if the customer 
elects not to accept an initial offer of identical, or substantially 
identical, transmission service. NAESB's queue flooding business 
practice allows a transmission provider to invalidate the submission of 
additional identical requests for transmission service when the sum of 
all previously submitted identical requests for transmission service 
equals or exceeds the total transfer capability on the requested path 
for any time period during the duration of the requests. We would 
consider the decision by a transmission provider to

[[Page 32695]]

deny service under the queue hoarding business practice and the 
decision to invalidate requests under the queue flooding business 
practice to be an act of discretion under 18 CFR 37.6(g)(4) (2005). As 
a result, the transmission provider is to log the actions it takes 
under the queue flooding and queue hoarding business practices.
---------------------------------------------------------------------------

    \363\ See Order No. 676 at P 19.
---------------------------------------------------------------------------

b. Queue Processing Business Practices
    390. The set of uniform business practices adopted in Order No. 676 
relating to transmission service price negotiation and on improving 
interaction between transmission customers and transmission providers 
over OASIS nodes. These business practices include standards for the 
time limit within which (1) transmission providers must respond to 
requests for transmission service, (2) transmission customers must 
confirm service, and (3) transmission providers must respond to a rebid 
from a transmission customer.\364\ These business practices also 
include negotiation priority rules, including the terms under which a 
request can be pre-empted and under which a request has the right-of-
first-refusal.\365\
---------------------------------------------------------------------------

    \364\ Id., Standards 001-4.6 and 001-4.13.
    \365\ Id., Standards 001-4.14 and 001-4.16.
---------------------------------------------------------------------------

    391. In the NOI, the Commission sought comment regarding whether 
there are provisions of the pro forma OATT that need to be reformed to 
better define the obligations of public utility transmission providers 
in responding to requests for transmission service.
Comments
    392. Several commenters asked that the Commission require 
transmission providers to post standard business practices that 
describe how the transmission provider will process requests for 
transmission service.\366\ MidAmerican suggests that transmission 
providers should be required to post on their OASIS sites a business 
practice documenting how they process their queues, requests outside 
the queue, and expected completion times. Calpine believes that the 
processing of requests for transmission service, and the deadlines 
associated with that process, should be standardized for all 
transmission service providers. For example, Calpine notes that 
Entergy's OASIS business practices state that Entergy will respond to 
fixed, hourly non-firm transmission service requests ``within 30 
minutes of receiving the request for the requests received earlier than 
1 hour before the service is to commence.'' By comparison, Calpine 
continues, SPP's tariff explains that hourly, non-firm transmission 
service requests for the next hour may be submitted no later than 20 
minutes prior to the start of service.
---------------------------------------------------------------------------

    \366\ E.g., Calpine, MidAmerican, and TDU Systems.
---------------------------------------------------------------------------

Discussion
    393. Order No. 676 contains many of the business practices we 
expect transmission providers to follow when they process requests for 
transmission service, including the issue Calpine raises in its 
comments about discrepancies between Entergy's and SPP's processes for 
requests for hourly non-firm transmission service. Calpine's comment 
addresses the deadline for transmission customers to submit requests 
for non-firm hourly point-to-point service and the deadline for 
transmission providers to respond to requests for non-firm hourly 
point-to-point service. Standard 001-4.13 in Order No. 676 indicates 
that transmission providers should use their best efforts to respond to 
requests for non-firm hourly point-to-point service that are submitted 
less than an hour prior to start and transmission providers should 
respond within 30 minutes to requests that are submitted more than an 
hour before start. In addition, in this NOPR we have provided 
additional clarity regarding the calculation of ATC and requirements 
for processing rollover requests. We also provide general guidance 
regarding which business practices should be filed as part of a 
transmission provider's OATT and which should be posted on OASIS. Given 
this additional clarity and the business practices already mandated by 
Order No. 676, we seek comment on whether commenters believe additional 
standardization of request queue processing is necessary. If so, we 
seek comment on the specific issues commenters believe are not clearly 
prescribed in Order No. 676 or this NOPR and which require additional 
mandatory queue processing business practices.
c. Reservation Priority
    394. Section 13.2 of the pro forma OATT requires transmission 
providers to process requests for long-term firm point-to-point service 
on a first-come, first-served basis. In the NOI, we asked whether the 
first-come, first-served approach to reservation priorities has 
resulted in a fair and equitable means of allocating transmission 
capacity when the transmission system is oversubscribed. If not, we 
asked whether an alternative approach should be implemented.
Comments
    395. Most transmission providers and federal power agencies respond 
that the first-come, first-served approach to allocating transmission 
service is the best alternative available.\367\ Several merchant 
generators and public power entities concur that no better alternative 
exists.\368\ Several commenters suggest that the first-come, first-
served approach may provide an advantage to transmission customers who 
have the financial resources to purchase software and employ staff to 
continually monitor OASIS sites.\369\ Santa Clara states that entities 
that have superior software and are able to consistently procure 
capacity to the exclusion of other market participants may have an 
unfair advantage.
---------------------------------------------------------------------------

    \367\ E.g., Ameren, EEI, Nevada Companies, TVA, and WAPA.
    \368\ E.g., NRECA, Powerex, Public Power Council, Sempra, and 
TDU Systems.
    \369\ E.g., Bonneville and Santa Clara.
---------------------------------------------------------------------------

    396. For the short-term market, Bonneville contends, the first-
come, first-served approach has two defects: (1) It advantages larger 
and better-financed transmission customers, which can continually 
monitor OASIS sites and submit requests electronically the moment new 
ATC is posted; and (2) it results in arbitrary awards of transfer 
capability when one customer's submission precedes a second customer's 
submission by mere seconds. Bonneville suggests that the Commission 
modify the first-come, first-served rule for awarding short-term firm 
point-to-point service capacity so that all requests submitted within a 
given time-frame are considered simultaneously submitted.
    397. Several commenters propose some version of priority preference 
for requests for transmission service that are pre-confirmed.\370\ 
Bonneville states that transmission customers flood the queue with 
unconfirmed requests to force competitors with higher queue positions 
to extend the length of their requests to retain their queue positions.
---------------------------------------------------------------------------

    \370\ E.g., Bonneville, Entergy, and South Carolina E&G.
---------------------------------------------------------------------------

    398. Bonneville suggests that the Commission consider reducing the 
time transmission customers have to confirm requests for short-term 
transmission service after the transmission provider has accepted a 
request for short-term transmission service. Bonneville states that a 
shorter time-frame would clear the short-term firm transmission market 
more quickly and make it more difficult for transmission customers to 
tie up scarce transfer capability.

[[Page 32696]]

    399. Powerex suggests that the Commission clarify its reservation 
priority standards so that when transmission providers make use of 
discounts in short-term service, price (not to exceed the ceiling 
price) should be the third-level tie breaking mechanism, with higher-
priced requests of equal duration having greater priority and requests 
earlier in the open access same-time information system having right of 
first refusal to match subsequent requests. Powerex states that in the 
presence of discounting, the open access transmission tariff allows a 
higher value service (firm) to be sold at a lower price than a lower 
value service (non-firm) even in the same operating horizon, because 
price based displacement only applies to short-term non-firm 
transmission services.
Discussion
    400. In response to comments that transmission customers that have 
the financial resources to purchase software and employ staff to 
continually monitor OASIS sites have an unfair advantage under a first-
come, first-served approach, we seek comment regarding whether any such 
advantage would be mitigated if all requests submitted within a 5-
minute window, with duration as a tie breaker, were deemed to have been 
submitted simultaneously. We also seek comment on whether transmission 
customers could game a 5 minute equivalent priority standard to request 
transmission service only after another transmission customer has made 
a request. To the extent we adopt a 5 minute equivalent priority 
standard, we propose to allocate capacity on a pro rata basis, though 
we seek comment on other methods for allocating limited transmission 
capacity among equivalent priority requests of equal duration.
    401. We also propose to change the priority rules to give priority 
to pre-confirmed requests. As a result, a pre-confirmed short-term 
request for firm transmission service would preempt any non-pre-
confirmed short-term requests, regardless of duration. Similarly, a 
pre-confirmed request for long-term firm transmission service would 
preempt a request for long-term transmission service that is not pre-
confirmed. We seek comment on whether this change to the reservation 
priority rules will alleviate concerns commenters have expressed 
regarding the flooding or jamming of the transmission queue by 
transmission customers who submit multiple requests for transmission 
service.
    402. We propose to add price as a tie-breaker in determining 
reservation queue priority when the transmission provider is willing to 
discount transmission service. Price would serve as a tie-breaker after 
pre-confirmation for those requests that are not yet confirmed. As a 
result, a pre-confirmed request for short-term firm point-to-point 
service would preempt another pre-confirmed request for short-term firm 
point-to-point service that has an earlier queue time, and an equal or 
shorter duration but a lower offer price. However, a request for short-
term firm point-to-point service that is not pre-confirmed would not 
preempt a pre-confirmed request for short-term firm point-to-point 
service that has an earlier queue time, and an equal or shorter 
duration but a lower offer price.
6. Designation of Network Resources
a. Qualification as a Network Resource
    403. Taken together, the following sections of the pro forma OATT 
describe the resources a network customer can appropriately designate 
as a network resource. Section 30.1 of the pro forma OATT describes 
network resources as all generation owned or purchased by the network 
customer designated to serve network load under the tariff. Section 
30.1 also indicates that network resources may not include resources 
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 noninterruptible basis. Pursuant to section 30.7 of the pro 
forma OATT, 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 network service. 
Section 29.2 requires the network customer to provide the following 
information about a power purchase agreement that is to serve as a new 
designated network resource: source of supply, control area location, 
transmission arrangements and delivery point(s) to the transmission 
provider's transmission system.
    404. The Commission has issued a number of orders that clarify 
which resources meet the criteria set out in sections 30.1 and 30.7 of 
the pro forma OATT. In MSCG, the Commission stated that network 
resources must be generating resources owned by the network customer or 
purchases of noninterruptible power under executed contracts that 
require the network customer to pay for the purchase.\371\ In WPPI, the 
Commission found that a network customer can designate as a network 
resource a system purchase that is not backed by a specific 
generator.\372\ The Commission found that Wisconsin Public Service 
Corporation (WPS) had appropriately designated a power purchase as a 
network resource, even though the power purchase agreement did not 
require WPS to take energy around the clock and allowed WPS to convert 
its energy purchase to a discounted product that could be 
interrupted.\373\ In addition, the Commission stated that because the 
pro forma OATT requires a power purchase to be noninterruptible, third-
party transmission arrangements to deliver the resource to the network 
have to be noninterruptible as well.\374\ In Illinois Power, the 
Commission found that a firm purchase need not be backed by a capacity 
purchase to qualify as a network resource.\375\
---------------------------------------------------------------------------

    \371\ Morgan Stanley Capital Group v. Illinois Power Co., 83 
FERC ] 61,204 at 61,911-12 (1998), order on reh'g, 93 FERC ] 61,081 
(2000) (MSCG).
    \372\ Wisconsin Public Power Inc. v. Wisconsin Public Service 
Corp., 84 FERC ] 61,120 at 61,650-51 (1998) (WPPI).
    \373\ Id.
    \374\ Id. at 61,660.
    \375\ Illinois Power Co., 102 FERC ] 61,257 at P 14 (2003), 
reh'g denied, 108 FERC ] 61,175 (2004) (Illinois Power).
---------------------------------------------------------------------------

    405. In the NOI, the Commission sought comment regarding whether 
network resources consisting of firm contracts that do not specify 
generation sources until the energy is scheduled (so-called ``seller's 
choice contracts'') are a problem. The Commission also sought comment 
on the specific difficulties entities have experienced with designation 
of network resources and asked what reforms are needed to the 
designations provision in the pro forma OATT.
Comments
    406. A number of commenters indicate that firm contracts that do 
not specify generation sources are acceptable network resources as long 
as the network customer specifies enough information for the 
transmission provider to identify how the contract power will enter its 
control area.\376\ Bonneville suggests that the customer should be 
required to identify the point(s) of receipt on the transmission 
provider's system whenever it designates a network resource. EEI states 
that the designation of seller's choice contracts as network resources 
is only problematic if the seller's choice contract permits the seller 
to choose the

[[Page 32697]]

flowgate path over which the energy will be delivered. EEI further 
explains that no issue is present if the seller is limited to a single 
path or flowgate. On the other hand, PNM-TNMP argues that allowing 
seller's choice contracts to be considered network resources 
significantly complicates transmission planning, as virtually none of 
the information required by section 29.2 of the OATT can be provided.
---------------------------------------------------------------------------

    \376\ E.g., Bonneville, EEI, Nevada Companies, Public Power 
Council, and TVA.
---------------------------------------------------------------------------

    407. Several commenters cited specific difficulties with or 
suggested specific modifications to the network designation provisions 
of the tariff. APPA indicated that under the liquidated damages 
provisions in the EEI contract, it is the buyer's responsibility to go 
out into the market to purchase replacement supplies (cover), and the 
seller then pays the buyer the difference between the contract price 
and the cover price. APPA states that these provisions are not 
consistent with the concept of having to specify generation resources 
or contracts as network resources, since the actual source and supplier 
of generation may well change at a time when both wholesale power 
supplies and transmission capacity are at a premium. Ameren suggests 
that the Commission clarify that liquidated damages products cannot be 
designated network resources. Ameren states that a liquidated damages 
contract allows a supplier to walk away from a deal if it can obtain a 
price elsewhere high enough to offset the liquidated damages 
provisions. Ameren argues that liquidated damages contracts are 
financial instruments that produce no electricity. MidAmerican also 
contends that provisions for designating liquidated damages contracts 
as network resources should be eliminated. Southwestern urges the 
Commission to reform the OATT to make it clear that a firm purchased 
power contract with liquidated damages should be eligible to be 
considered a designated network resource.
Discussion
    408. We propose to maintain our current policy regarding the power 
purchase agreements that network customers may designate as network 
resources. In particular, a network customer will continue to be able 
to designate resources from system purchases not linked to a specific 
generating unit, provided the purchase power agreement is not 
interruptible for economic reasons, does not allow the seller to fail 
to perform under the contract for economic reasons, and the executed 
contract requires the network customer to pay for the purchase. In 
addition, third party transmission arrangements to deliver the purchase 
to the network have to be noninterruptible as well.
    409. In response to comments that seller's choice contracts are 
problematic because the network customer can provide limited, if any, 
information required by section 29.2 of the pro forma OATT, we 
reiterate that a request to designate a new network resource must 
include the information specified in section 29.2(v), including the 
source of supply, control area location, transmission arrangements, and 
delivery point(s) to the transmission provider's transmission system. 
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. A power 
purchase agreement that is structured so that a network customer cannot 
specify all of the information required by section 29.2(v) cannot be 
designated as a network resource.
    410. In response to suggestions that liquidated damages products 
should not be designated network resources because they are 
interruptible for economic reasons, we clarify that network customers 
may not designate as network resources those power purchase agreements 
that give the seller a contractual right to compensate the buyer 
instead of delivering power even if the seller is able to deliver 
power. For instance, a network customer may not designate as a network 
resource a purchase agreement that allows the seller to interrupt 
service for reasons other than reliability, but allows the buyer to 
force delivery at a higher price. In addition, a network customer may 
not designate as a network resource a purchase agreement that requires 
a seller to pay the buyer's cost of replacement power when the seller 
chooses not to deliver energy for economic reasons.
b. Documentation for Network Resources
    411. Section 30.2 of the pro forma OATT stipulates that a network 
customer request the designation of a new network resource by a request 
for modification of service pursuant to an application under section 29 
of the pro forma OATT, and section 29.2 stipulates that the network 
customer must provide specified information about its designated 
network resources. The Commission found in WPPI that transmission 
customers may need to document compliance with specific requirements 
for obtaining tariff service, possibly including contractual 
terms.\377\ The Commission went on to state that it expected a 
transmission provider's merchant function to police its own compliance 
with tariff obligations.\378\
---------------------------------------------------------------------------

    \377\ WPPI at 61,660.
---------------------------------------------------------------------------

Comments
    412. LG&E suggests that the pro forma OATT require the transmission 
provider to have a process to verify that each load-serving entity has 
a contractual right to the resources they are designating. LG&E argues 
this would help eliminate concerns over double booking of resources by 
two parties. EPSA states that transmission providers have attempted to 
require customers to demonstrate that they have obtained contracts 
covering an annual period, rather than allowing customers to provide 
reasonable advance notice for each contract during the service period. 
EPSA asks the Commission to prohibit this practice.
---------------------------------------------------------------------------

    \378\ Id.
---------------------------------------------------------------------------

Discussion
    413. We clarify that transmission providers are not responsible for 
verifying that the generating units and power purchase agreements 
network customers designate as network resources satisfy the 
requirements in sections 30.1 and 30.7 of the pro forma OATT. While 
transmission providers are responsible for verifying that the network 
customer has provided all the information section 29.2 requires the 
network customer to provide, the transmission provider is not 
responsible for obtaining contractual terms to verify requirements in 
sections 30.1 and 30.7 of the pro forma OATT. The transmission provider 
continues to have the responsibility to verify that third-party 
transmission arrangements to deliver the purchase to the transmission 
provider's system are firm.
    414. We propose to require the transmission provider's merchant 
function as well as network customers to include a statement with each 
application to designate a new network resource that attests that: (1) 
The transmission customer owns or has committed to purchase the new 
designated network resource, and (2) the new designated network 
resource comports with the requirements for designated network 
resources. The network customer should include this attestation in the 
customer's comment section of the request when it confirms the request. 
Similarly, we propose that all entities that submit an application for 
network service be required to

[[Page 32698]]

include a statement with the application for service that attests that, 
for each network resource identified in the application for service: 
(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.
    415. We propose that if the network customer does not include an 
attestation when it confirms its request, the transmission provider 
will notify the network customer within 15 days of confirmation that 
its request is deficient. Wherever possible, the transmission provider 
will attempt to remedy deficiencies in the request through informal 
communications with the network customer. If such efforts are 
unsuccessful, the transmission provider will terminate the network 
customer's request and change the status of the request on OASIS to 
``retracted.'' This termination will be without prejudice to the 
network customer submitting a new request that includes the required 
attestation. The network customer will be assigned a new priority 
consistent with the date of the new request.
    416. In the event that the transmission provider or any 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, we 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 
Enforcement Policy Statement. We encourage the transmission provider 
and other market participants to use the Commission's Enforcement 
Hotline to report instances when they believe a network customer has 
designated as a network resource a resource that does not meet the 
criteria for network resources.
c. Undesignation of Network Resources
    417. Section 28.2 of the pro forma OATT requires the transmission 
provider, on behalf of its native load customers, to designate 
resources and loads in the same manner as any network customer under 
Part III of the pro forma OATT (Network Integration Transmission 
Service). The information provided by the transmission provider must be 
consistent with the information it uses to calculate ATC. Section 30.3 
of the pro forma OATT allows the network customer to terminate the 
designation of all or part of a generating resource as a network 
resource at any time, though the network customer should provide 
notification to the transmission provider as soon as reasonably 
practicable.
    418. In Order No. 888-B, the Commission clarified that the pro 
forma OATT allows network customers to designate network resources over 
shorter time periods. The Commission indicated that a network customer 
that seeks to engage in firm sales from its current designated network 
resources may terminate the generating resource (or a portion of it) as 
a network resource pursuant to section 30.3 of the pro forma OATT and 
request, as set forth in section 29 of the pro forma OATT, that the 
same generation resource be designated as a network resource effective 
with the end of its power sale.\379\
---------------------------------------------------------------------------

    \379\ Order No. 888-B at 62,093
---------------------------------------------------------------------------

    419. In the NOI, the Commission sought comment on whether network 
customers should be allowed to ``undesignate'' portions of their 
designated network resources on a short-term basis in order to make 
firm sales from these resources.
Comments
    420. Most commenters suggest that the Commission continue to allow 
network customers to undesignate a portion of their designated network 
resources on a short-term basis in order to make firm sales.\380\ APPA 
argues that the ability of network customers to undesignate their 
network resources on a short-term basis is an important aspect of Order 
No. 888-B and should be preserved. APPA states that the flexibility 
afforded to network resource customers allows them to lay off excess 
power supplies that they do not need to serve their designated loads 
during off-peak demand periods. APPA and EEI contend that this 
increases the number of wholesale sellers in the market during non-peak 
periods, and this supports wholesale competition for power supply 
sales.
---------------------------------------------------------------------------

    \380\ E.g., APPA, EEI, Entergy, Nevada Companies, Public Power 
Council, Southern, and TVA.
---------------------------------------------------------------------------

    421. Several commenters suggest that network customers should have 
the same right as transmission providers to undesignate network 
resources to make off-system sales.\381\ APPA states that the 
Commission should make explicit the requirement that the transmission 
provider must provide the same flexibility to its network customers as 
it does to its own merchant function in designating and terminating 
network resources.
---------------------------------------------------------------------------

    \381\ E.g., APPA, NRECA, and Public Power Council.
---------------------------------------------------------------------------

    422. NRECA asserts that public utility transmission providers must 
be required to undesignate resources or portions thereof in order to 
make firm sales out of generation fleets that they have designated as a 
network resource.
Discussion
    423. We propose to continue to allow network customers to 
undesignate a portion of their network resources on a short-term basis 
to make off-system sales. We reiterate that a network customer may 
redesignate the resource by making a request to designate a new network 
resource. In response to comments that the transmission provider also 
should be required to undesignate network resources when the 
transmission provider makes firm off-system sales, we reiterate that 
the transmission provider must abide by both the requirement in section 
28.2 of the pro forma OATT to designate its network resources in the 
same manner as network customers and the prohibition in section 30.1 of 
the pro forma OATT against making firm sales from its designated 
network resources. That is, the transmission provider and all network 
customers must designate their network resources and are prohibited 
from making firm sales from designated network resources. To the extent 
the transmission provider or a network customer wants to make a firm 
sale from a network resource, it must undesignate the resource pursuant 
to section 30.3 of the pro forma OATT. The network customer, including 
the transmission provider itself, can request to redesignate the 
resource by making a request to designate a new network resource 
pursuant to section 30.2 of the pro forma OATT.
    424. We seek comment on the amount of time prior to operation that 
the transmission provider and other network customers should be 
required to terminate a network resource to ensure that the appropriate 
set of network resources are included in the ATC calculation.
7. Clarifications Related to Network Service
Secondary Network Service
    425. Section 28.4 of the pro forma OATT allows a network customer 
to deliver economy energy purchases to its network load from non-
designated network resources on an as-available basis without 
additional charge. In Order No. 888, the Commission described economy 
energy purchases as energy that displaces firm network resources.\382\
---------------------------------------------------------------------------

    \382\ Order No. 888 at 21,751.
---------------------------------------------------------------------------

    426. The use of secondary network service to deliver purchased 
power

[[Page 32699]]

when a network customer is making off-system sales was raised in 
several Commission investigations and audits. In Idaho Power, the 
Commission accepted a settlement with Idaho Power related to Idaho 
Power's incorrect use of the native load priority to access its 
transmission system.\383\ In Idaho Power, the utility's wholesale 
merchant function purchased power outside of Idaho Power's control area 
to facilitate an off-system sale and used secondary network service to 
bring the purchases into Idaho Power's control area.\384\ In accepting 
the settlement, the Commission stated that ``[i]t is axiomatic that the 
native load priority cannot be used to complete sales that are not 
necessary to serve native load.'' \385\ In MidAmerican, the Commission 
issued an audit report that contained a finding that MidAmerican's 
wholesale merchant function used network service instead of point-to-
point service to deliver short-term energy purchases to its control 
area that were not used to serve MidAmerican's native load.\386\
---------------------------------------------------------------------------

    \383\ Idaho Power Co., 103 FERC ] 61,182 at P 2 (2003) (Idaho 
Power).
    \384\ Id. at P 4.
    \385\ Id.
    \386\ MidAmerican Energy Co., 112 FERC ] 61,346 at P 6 (2005).
---------------------------------------------------------------------------

Comments
    427. South Carolina E&G asks the Commission to clarify whether 
specific methods used to bring sellers and buyers together in the 
wholesale market are appropriate under the pro forma OATT in its 
current form. South Carolina E&G notes that as a utility's native load 
forecasts evolve into real-time conditions, the utility may need to 
sell off excess energy. South Carolina E&G notes further that, as 
inexpensive sources of power become available off-system, the utility 
may engage in economy purchases of power for native load. South 
Carolina E&G asserts that such practices clearly benefit the market and 
safeguard native load customers' interests by ensuring that economy 
purchases minimize the price of consumers' power and/or giving the 
utility a market outlet for excess energy, thus avoiding the uneconomic 
backing down of lower cost generating units while retaining higher cost 
prescheduled purchases. South Carolina E&G urges the Commission to 
support the continuation of such practices.
Discussion
    428. We propose to clarify that a network customer may not use 
secondary network service to bring energy onto its system to support an 
off-system sale if the purchased power does not displace the customer's 
own higher cost generation. We propose to modify the section 28.4 of 
the pro forma OATT to clarify that a network customer may use secondary 
network service to deliver economy energy and we propose to add a 
definition for ``economy energy'' to the pro forma OATT. We propose to 
define ``economy energy'' as energy purchased by a network customer 
that displaces the customer's own higher cost generation for the 
purpose of serving the customer's designated network loads.
    429. While we reiterate that secondary network service may be used 
only to serve a network customer's designated network load, we do not 
intend to discourage market participants from identifying opportunities 
to profitably purchase for resale. We simply intend to ensure that all 
market participants compete on a comparable basis and use point-to-
point service to complete all segments of a purchase for resale off-
system.
    430. We also do not intend to discourage network customers from 
purchasing off-system energy to lower the cost of serving network 
loads. A network customer may use secondary network service in hours 
when it is also making off-system sales. However, the network customer 
may do so only to deliver purchases that qualify as economy energy 
purchases. In response to South Carolina E&G's observation that a 
utility's native load forecasts evolve in real-time to the point that 
the utility may need to sell off excess energy that was purchased off-
system, we note that our definition would allow a network customer to 
use network service to deliver off-system purchases when the network 
customer purchases the energy with the intent to serve native load.
    431. In enforcing this policy, we will apply the definition of 
``economy energy'' at the time the network customer commits to purchase 
energy. For instance, we will not take issue if a network customer uses 
secondary network service to deliver an hour-ahead purchase that costs 
less than the network customer's generation cost in the hour of 
operation. Similarly, we will not question the use of secondary network 
service by a network customer to deliver a day-ahead off-system 
purchase that costs less than the network customer's forecast 
generation cost, even if real-time system conditions evolve so that the 
realized generation cost is less than the cost of the purchased energy. 
We also would not take issue with a network customer that uses network 
service to deliver off-system block energy because the purchased energy 
is more economic than using its network resources, but makes off-system 
sales during some hours when the block energy purchase is scheduled. In 
other words, in enforcing this policy, we will apply the definition of 
``economy energy'' as it applies to the entire period covered by the 
block purchase and not to a single hour within the block.
``[O]n an As-Available Basis''
    432. Section 28.4 of the pro forma OATT allows a network customer 
to use secondary network service to deliver economy energy purchases to 
its network load from non-designated resources ``on an as-available 
basis.'' However, the current pro forma OATT does not specify how a 
network customer must arrange for secondary network service.
Discussion
    433. We propose to modify section 28.4 of the pro forma OATT by 
clarifying that a network customer need not file an application for 
network service to receive secondary network service, but that all 
other requirements of Part III of the pro forma OATT (except for 
transmission rates) apply to secondary network service. In other words, 
a network customer must request secondary network service on OASIS in a 
manner consistent with pro forma OATT sections 18.1 and 18.2 
(Procedures for Arranging Non-Firm Point-To-Point Transmission 
Service).
Redirect of Network Service
    434. The current pro forma OATT does not include any provision to 
change the point of receipt for an off-system designated network 
resource, in a manner similar to redirect of point-to-point service. 
However, we are aware that several transmission providers have posted 
business practices that allow network customers either to substitute an 
off-system non-designated network resource for a designated network 
resource or to redirect the point of receipt associated with an 
existing network resource.
Discussion
    435. We propose to clarify that network customers may not redirect 
network service in a manner comparable to the way customers redirect 
point-to-point service. Unlike point-to-point service that is based 
upon a contract-path model consisting of a designated point of receipt 
and point of delivery, network service involves no identified contract 
path and is therefore not a directable service. Rather, network

[[Page 32700]]

service provides for the integration of designated network resources 
and loads using the entire transmission grid in a manner comparable to 
the transmission provider's use of the transmission grid to serve its 
native load customers. When a network customer wants to substitute one 
designated network resource for another, it should terminate the 
designation of the existing network resource and designate a new 
network resource. The network customer can then request to redesignate 
its original network resource by making a request to designate a new 
network resource. Alternatively, a network customer could use secondary 
network service when it wants to substitute a non-designated network 
resource for a designated network resource on an as-available basis.
8. Transmission Curtailments
    436. Section 1.7 of the pro forma OATT defines curtailment as ``a 
reduction in firm or non-firm transmission service in response to a 
transmission capacity shortage as a result of system reliability 
conditions.'' Curtailment provisions for point-to-point service are set 
forth in sections 13.7 and 14.7 for firm and non-firm transmission 
services respectively and the curtailment provisions for network 
service are contained in section 33. Complaints regarding improper 
curtailment of service by transmission providers have been made in a 
variety of proceedings and the Commission has found cases of improper 
curtailment in the past.\387\
---------------------------------------------------------------------------

    \387\ See, e.g., Consolidated Edison Co. of N.Y. v. Public Serv. 
Elec. & Gen. Co., 108 FERC ] 61,120 (2004).
---------------------------------------------------------------------------

    437. In the NOI, the Commission asked whether there is evidence of 
improper curtailment practices by public utility transmission providers 
or customers that warrants reforms to the pro forma OATT. If there is, 
we requested that commenters provide specific examples of such 
practices. We also asked whether transmission providers engaging in 
improper curtailments should be subject to monetary penalties or other 
remedies for market manipulation.
Comments
    438. EEI argues that there do not appear to be many instances of 
improper curtailments and many utilities state that they are not aware 
of any improper curtailments by public utility transmission providers. 
For example, Southern states that curtailments are performed on a non-
discriminatory basis, in accordance with applicable OATT provisions. 
Ameren, KCP&L, and PNM-TNMP state that they are not aware of any 
improper practices that would warrant reforms to the pro forma OATT. 
APPA does not advocate changes to the pro forma OATT regarding 
curtailment, stating that its members express more concerns about the 
denial of service prior to and at the time of scheduling than they do 
regarding curtailment of service once it has commenced. However, APPA 
also notes that most of its members use firm service that is unlikely 
to be interrupted once it is scheduled. Public Power Council, 
Snohomish, MEAG and Salt River concur with APPA that OATT reforms are 
not needed for curtailments.
    439. Transmission customers, particularly IPPs, generally have a 
different view, arguing that the reasons for curtailment are difficult 
to discern, and that information is often insufficient to determine 
whether curtailments have been performed correctly. Northwest IPPs 
state curtailments frequently appear arbitrary. Powerex argues that 
incomplete postings on many transmission systems and the lack of 
transparency in curtailment data could mask improper curtailment. 
Calpine states that it is usually difficult to determine whether a 
curtailment of service is truly justified by system reliability factors 
because the operational facts underlying the utility's curtailment 
decision are unknown. It argues that the criteria for utility 
curtailment decisions are not standardized, making it difficult to 
determine the propriety of curtailment decisions, particularly when 
curtailment is internal to a single area and not performed through the 
NERC TLR process. Calpine recommends that the terms and conditions for 
curtailments be standardized by the new reliability organizations 
created by EPAct 2005, that such terms and conditions be made a formal 
part of the pro forma OATT and the OATTs of public, private and federal 
utilities, and that these be posted on the transmission provider's 
OASIS. Calpine further recommends that regional NERC organizations be 
requested to audit the curtailment practices of all utilities that are 
not members of an RTO/ISO. Constellation asserts that TLRs are a 
``blunt and inefficient mechanism'' for curtailment and calls for a 
requirement that transmission providers provide redispatch options.
    440. In reply to claims that vertically integrated utilities 
provide inadequate information on curtailments, Southern states that 
existing OASIS requirements already require utilities to post a 
considerable amount of information on curtailments, and that the 
information currently posted is adequate to meet customers' needs. 
Nevertheless, Southern also states that while those rules have been 
effective in achieving their intended purpose, incremental additions to 
the information that is available through OASIS could assure customers 
that they have all of the information they need to make prudent 
decisions about transmission service and that they are being treated in 
a fair, equitable, and non-discriminatory way.
    441. Commenters appear divided on the issue of whether there should 
be penalties for improper curtailments. The most common view, expressed 
by EEI and others, is that penalties for improper curtailments should 
be assessed only if the Commission finds that the transmission provider 
imposed the curtailment with the intent to treat a customer in an 
unduly discriminatory or preferential manner. Other commenters 
expressed a wide range of views. Alcoa states that improper 
curtailments should be the subject of monetary penalties. Santa Clara 
contends that transmission providers should be fully liable for any 
damages caused by improper curtailments. On the other hand, Southern 
argues that curtailment is a reliability issue and it would be unwise 
to subject transmission providers to after-the-fact assessments of 
their curtailment decisions. KCP&L notes that the responsibility for 
calling a TLR rests with the reliability coordinator, who makes 
decisions based on the NERC standard, so that penalties for improper 
curtailment activity should be a subject for the ERO.
Discussion
    442. The Commission reminds both transmission providers and 
customers that our regulations require posting of transmission 
curtailment information on OASIS. The OASIS regulations state:

    When any transaction is curtailed or interrupted, the 
Transmission Provider must post notice of the curtailment or 
interruption on the OASIS, and the Transmission Provider must state 
on the OASIS the reason why the transaction could not be continued 
or completed.
    (ii) Information to support any such curtailment or 
interruption, including the operating status of the facilities 
involved in the constraint or interruption, must be maintained and 
made available upon request, to the curtailed or interrupted 
customer, the Commission's Staff, and any other person who requests 
it, for three years.\388\
---------------------------------------------------------------------------

    \388\ We note that we are proposing to change this information 
retention period to five years, consistent with our other proposed 
changes to the OASIS information retention provisions.

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

[[Page 32701]]

    (iii) Any offer to adjust the operation of the Transmission 
Provider's system to restore a curtailed or interrupted transaction 
must be posted and made available to all curtailed and interrupted 
Transmission Customers at the same time.\389\
---------------------------------------------------------------------------

    \389\ 18 CFR 37.6(d)(3) (2005).

    443. Those commenting that they have inadequate information about 
curtailments do not clearly state whether the source of this deficiency 
lies in: (1) The inadequacy of our standards, (2) inadequate compliance 
with these standards, (3) difficulties in dealing with the way the 
information is provided, or (4) some other area. We are, however, 
mindful that objective review of curtailments can require a 
considerable amount of information, some of which may not be provided 
under the present OASIS regulations, or may be provided in an 
inefficient manner. For example, we recognize that it is difficult for 
a customer to determine what network resources were available to the 
transmission provider that could have been redispatched consistent with 
pro forma OATT sections 30.5 and 33.2 to relieve the transmission 
constraint that led to a transmission curtailment. Another example may 
be discerning which discrete transaction(s) could be curtailed on a 
non-discriminatory basis to effectively relieve the constraint 
consistent with pro forma OATT section 13.6. We seek comment on whether 
additional requirements would improve the transparency of transmission 
curtailment information and the ability of customers to make use of 
that information.
    444. With respect to the imposition of penalties, the Commission 
recognizes that the transmission curtailment decision is a reliability 
decision that should be based on applicable reliability standards. 
Moreover, we note that the need for transmission curtailment depends on 
many factors outside the control of an individual transmission 
provider, including loop flows throughout an interconnection. 
Accordingly, we will not propose generic penalties for improper 
transmission curtailments in this rulemaking. However, the absence of 
generic penalties should not be construed to mean that we will tolerate 
intentional behavior that subjects customers to unduly discriminatory 
or preferential actions. We remain vigilant in monitoring for 
intentionally discriminatory provision of transmission service, and 
stand ready to use our enforcement powers and penalty authority when 
needed.
9. Standardization of Rules and Practices
    445. In Order No. 888, the Commission required each public utility 
that owns, controls, or operates facilities used for transmitting 
electric energy in interstate commerce to file, pursuant section 205 of 
the FPA, a pro forma OATT under which it would provide open access 
transmission services. However, certain rules, standards and practices 
governing the provision of such transmission service (e.g., public 
utility business practices) are not reflected in the pro forma OATT. 
Only when a public utility adopts a rule, standard or practice that 
significantly affects its rates and services has the Commission 
required it to make a filing pursuant to FPA section 205 to amend its 
OATT.\390\ The Commission has applied this policy using a ``rule of 
reason'' test.\391\
---------------------------------------------------------------------------

    \390\ E.g., Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 
1985).
    \391\ See, e.g., Public Serv. Comm'n of N.Y. v. FERC, 813 F.2d 
448, 454 (D.C. Cir. 1987) (holding that the Commission properly 
excused utilities from filing policies or practices that dealt only 
with matters of ``practical insignificance'' to serving customers); 
Midwest Independent Transmission System Operator, Inc., 98 FERC ] 
61,137 at 61,401 (``It appears that the proposed Operating Protocols 
could significantly affect certain rates and service and as such are 
required to be filed pursuant to Section 205.''), order granting 
clarification, 100 FERC ] 61,262 (2002).
---------------------------------------------------------------------------

    446. The rule of reason test has arisen primarily with respect to 
protocols or operating procedures used by RTOs and ISOs. For example, 
the Commission has held that while the business practices manuals of 
the Midwest ISO implicate the Commission's jurisdiction because they 
generally involve ``the installation, operation, or use of facilities 
for the transmission or delivery of power * * * in interstate 
commerce,'' they do not require a FPA section 205 filing because ``they 
mostly involve general operating procedures.''\392\ In other cases, the 
facts have required the filing of the rule, standard or practice. For 
example, CAISO proposed to post certain, technical, operational and 
business standards related to dynamic scheduling on its Web site and 
include only the rates under its OATT. There, the Commission found that 
the details contained in the standards are practices that may affect 
the terms and conditions of service significantly, and therefore, under 
the Commission's ``rule of reason,'' must be filed under FPA section 
205.\393\
---------------------------------------------------------------------------

    \392\ Midwest Independent Transmission System Operator, Inc., 
108 FERC ] 61,163 at P 656, 658, order on reh'g, 109 FERC ] 61,157 
(2004), order on reh'g, 111 FERC ] 61,043, order on reh'g, 112 FERC 
] 61,086 (2005); see also PJM Interconnection, L.L.C., 81 FERC ] 
61,257 at 62,267 (1997) (finding no reason to require filing of the 
PJM Manuals but requiring that such manuals be available for public 
inspection on a permanent basis), order on reh'g, 92 FERC ] 61,282 
(2000).
    \393\ California Independent System Operator Corp., 107 FERC ] 
61,329 at P 21-22 (2004); see also Southwest Power Pool, Inc., 112 
FERC ] 61,303 at P 25 (2005) (requiring that the SPP OATT provide 
sufficient information for market participants to fully understand 
SPP's implementation of an imbalance market), reh'g dismissed, 113 
FERC ] 61,115 (2005); PJM Interconnection, L.L.C., 104 FERC ] 61,124 
at P 61 (requiring PJM to place all procedures, standards and 
requirements for proposing that a transmission owner construct a 
specific upgrade, and all procedures for charging customers, in its 
tariff, not in its manuals), order on reh'g, PJM Interconnection, 
L.L.C., 105 FERC ] 61,123 (2003).
---------------------------------------------------------------------------

    447. In the NOI, the Commission asked: (1) Whether all rules, 
standards and practices should be required to be included in public 
utilities' OATTs? (2) If not all, which of such rules, standards and 
practices should be included in public utilities' OATTs? and (3) Should 
rules, standards and practices not required to be included in public 
utilities' OATTs be required to be posted on OASIS to increase 
transparency?
Included in Open Access Transmission Tariffs
    448. Some commenters argue that the rules, standards and practices 
governing the provision of transmission service should be included in 
public utilities' OATTs.\394\ Occidental states that the inclusion of 
rules, standards and practices governing the provision of transmission 
service in public utilities' OATTs will add much needed clarity as to 
how transmission service is provided. EPSA states that while it may not 
be necessary, or desirable, to require all business practices to be 
incorporated into the OATT, there have been instances where 
transmission providers have adopted business practices that are 
inconsistent with their OATT requirements or that should have been 
filed as OATT amendments. Some commenters also support the inclusion of 
the NAESB standards in the OATT.\395\
---------------------------------------------------------------------------

    \394\ E.g., Occidental, TAPS, and Williams.
    \395\ E.g., Salt River and Snohomish.
---------------------------------------------------------------------------

    449. In contrast, some commenters oppose including rules, standards 
and practices in the OATT.\396\ EEI argues that rules, standards and 
practices should not be included as part of an OATT unless they 
significantly affect rates and service under the OATT. EEI states that 
this is consistent with the Commission's current practice for the 
inclusion of manuals in an OATT. Indicated New York Transmission Owners 
state that the inclusion of rules, standards and practices in the OATT 
is

[[Page 32702]]

unnecessary and would administratively encumber any future revisions to 
the practices and rules by requiring conforming tariff filings.
---------------------------------------------------------------------------

    \396\ E.g., BPA, EEI, MidAmerican, and Southern.
---------------------------------------------------------------------------

Posted on OASIS
    450. Several commenters believe it would be appropriate to post 
rules, standards and practices on public utilities' OASIS sites.\397\ 
For example, EEI states that it would be appropriate to post all rules, 
standards and practices that are not part of the OATT on a transmission 
provider's OASIS. APPA asserts that, in particular, transmission 
providers should post the methodologies they use to develop ATC and ATC 
calculations should be periodically verified by an independent third 
party.\398\
---------------------------------------------------------------------------

    \397\ E.g., APPA, BPA, EEI, EPSA, MidAmerican, and Southern.
    \398\ See supra Part V.A addressing posting requirements for ATC 
calculation.
---------------------------------------------------------------------------

    451. Other commenters contend that rules, standards and practices 
should be posted on public utilities' OASIS sites only when they are 
not required to be filed.\399\ TAPS argues that any rules, standards 
and practices not required to be filed must be publicly posted on the 
transmission provider's OASIS to provide needed transparency, because 
including essential terms in business practices that are not posted 
makes it very difficult for customers to understand if they are being 
treated fairly by the transmission provider. TDU Systems asserts that 
requiring posting on transmission providers' OASIS sites of any 
standards and practices not included in their OATTs would facilitate 
transactions across several transmission provider systems, especially 
where transmission providers are not participating in RTOs or 
ISOs.\400\ Williams goes one step further and recommends that the 
Commission require that transmission providers both file with the 
Commission and post on their OASIS sites, all policies, practices and 
interpretations used or relied upon to evaluate a request for 
transmission service.
---------------------------------------------------------------------------

    \399\ E.g., Progress Energy and TAPS.
    \400\ Suez Energy NA emphasizes that the posting of rules, 
standards, and practices on OASIS merely ensures that they are 
transparent, it does not ensure that they are non-discriminatory.
---------------------------------------------------------------------------

Discussion
    452. There appears to be broad consensus among the commenters that 
rules, standards and practices not required to be included in a 
transmission provider's pro forma OATT should be posted on the 
transmission provider's OASIS. We agree and propose to require 
transmission providers to post on OASIS all of their rules, standards 
and practices that relate to transmission services. We believe this 
proposal will provide greater transparency and mitigate the potential 
for undue discrimination against customers taking transmission service 
under the transmission provider's OATT.\401\ However, we seek comment 
on how to determine what ``relates'' to transmission service to 
facilitate a consistent interpretation and to minimize discretion on 
what rules, practices and standards should be posted on OASIS.\402\
---------------------------------------------------------------------------

    \401\ We clarify that posting rules, practices and standards on 
the transmission provider's OASIS--in lieu of filing such practices 
with the Commission as part of the transmission provider's pro forma 
OATT--neither insulates a transmission provider from complaints nor 
confers a just and reasonable presumption. We encourage customers to 
call the Commission's Enforcement Hotline with complaints about the 
application of such rules, standards and practices should they 
experience problems with their transmission providers. To the extent 
customers are not satisfied with responses from utilities, they 
should contact the Commission's Enforcement Hotline via telephone 
(202) 502-8390, toll-free 1-888-889-8030, fax (202) 208-0057, or at 
http://www.ferc.gov/cust-protect/enforce-hot.asp.

    \402\ We note that certain rules and practices are already 
required to be posted on OASIS. See, e.g., Order No. 889; Open 
Access Same-Time Information Systems, Order No. 605, 64 FR 34117 
(Jun. 25, 1999), FERC Stats. and Regs. ] 31,075 (1999); Order No. 
676.
---------------------------------------------------------------------------

    453. Commenters presented wide ranging positions on the issue of 
what rules, standards and practices to include in the OATT. We do not 
propose to modify our existing policy on this issue at this time.\403\ 
We agree with EPSA's concern that requiring transmission providers to 
include all of their rules, standards and practices in their OATTs 
could decrease a transmission provider's flexibility to change 
businesses practices and respond to the requests of customers. 
Additionally, we believe that requiring transmission providers to file 
all of their rules, standards and practices in their OATTs would be 
impractical and potentially administratively burdensome.\404\
---------------------------------------------------------------------------

    \403\ See supra notes 391-393 and accompanying text.
    \404\ Of course, we will require the filing of certain rules, 
standards and practices when circumstances require. In Order No. 
676, the Commission, among other things, incorporated certain 
business standards developed by NAESB by reference into the 
Commission's regulations and required public utilities to file 
revisions to their OATTs to include these standards. Order No. 676 
at P 20.
---------------------------------------------------------------------------

    454. We propose to require, however, that creditworthiness and 
security requirements be included in a transmission provider's OATT. 
The creditworthiness provision in section 11 of the pro forma OATT 
authorizes transmission providers to require ``reasonable credit review 
procedures'' in accordance with ``standard commercial practices,'' to 
determine the ability of transmission customers to meet service 
obligations. Furthermore, to protect transmission providers from the 
risk of non-payment, the provision authorizes the transmission provider 
to require as security a letter of credit or other forms of security 
consistent with the Uniform Commercial Code. In the Creditworthiness 
Policy Statement, the Commission explained that non-RTO or -ISO 
transmission providers generally have not incorporated creditworthiness 
or security requirements into their OATTs.\405\ The Commission stressed 
that transparency of credit procedures and security requirements can 
enhance market certainty and liquidity by allowing customers to 
determine for themselves the information they need to demonstrate 
creditworthiness and the amount and type of security they need to 
receive transmission service. In interpreting the ``reasonable credit 
review procedures'' requirement in section 11 of the pro forma OATT, 
the Commission stated that it expected transmission providers to post 
on their OASIS sites the process and methodologies used to evaluate a 
potential customer's creditworthiness and calculate the necessary 
security.\406\ But it also stated that it would ``consider 
standardizing credit procedures through a generic rulemaking if 
necessary to prevent undue discrimination.'' \407\
---------------------------------------------------------------------------

    \405\ Policy Statement on Electric Creditworthiness, 109 FERC ] 
61,186 at P 9 (2004) (Creditworthiness Policy Statement).
    \406\ Id. at P 12. The Commission explained that all 
transmission providers (including RTOs and ISO) were expected to 
``(1) make their credit-related practices more transparent and 
comprehensive; (2) post on their [OASIS sites] the procedures that 
they use to do their credit analyses; and (3) provide a customer 
with a written analysis setting forth how that entity applied its 
credit standards to that customer, if that customer is required to 
provide security.'' Id.
    \407\ Id. at P 15.
---------------------------------------------------------------------------

    455. Our preliminary conclusion is that a transmission provider's 
OATT should contain sufficient information about its credit process and 
requirements to enable customers to understand the information required 
to demonstrate creditworthiness and to determine for themselves the 
general amount and type of security they may need to provide in order 
to receive service. We therefore propose to amend section 11 of the pro 
forma OATT on creditworthiness to require each transmission provider to 
include its creditworthiness and security requirements in a new 
Attachment L to its OATT.

[[Page 32703]]

    456. In the Creditworthiness Policy Statement, the Commission 
explained that, to assess an applicant's credit risk, transmission 
providers should use both qualitative factors, such as the local 
regulatory environment or the applicant's history and financial 
policies, and quantitative factors, such as information included on the 
applicant's financial statements.\408\ We propose to require the new 
Attachment L to include such quantitative and qualitative criteria to 
determine the level of secured and unsecured credit. We also propose to 
require the new Attachment L to include 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. We propose to allow these basic elements to be 
supplemented with a credit guide or manual to be posted on OASIS.
---------------------------------------------------------------------------

    \408\ Id. at P 13 & nn.13-14. An evaluation using both sets of 
factors would allow an applicant without a credit rating or a strong 
balance sheet, but with solid credit, to meet the creditworthiness 
criteria. Id. at P 14.
---------------------------------------------------------------------------

    457. Though we are proposing to require transmission providers to 
incorporate the creditworthiness and security methodologies into their 
OATTs, we recognize that there is a balance here between the burden on 
the transmission provider of adding these methodologies to its OATT and 
the need for Commission review and approval if methodologies frequently 
change. We seek comment on whether the proposal is unduly burdensome.
10. OATT Definitions
    458. In the NOI, the Commission requested comment on whether new or 
amended pro forma OATT definitions were necessary. The Commission also 
noted that new section 215(a)(4) of the FPA, which was adopted as part 
of EPAct 2005, defines the term ``reliable operation.'' \409\ We 
therefore asked whether this definition should be incorporated in the 
pro forma OATT.
---------------------------------------------------------------------------

    \409\ EPAct 2005 sec. 1211(a) (to be codified at FPA section 
215(a), 16 U.S.C. 824o). Section 215(a)(4) defines ``reliable 
operation'' as ``operating the elements of the bulk power system 
within equipment and electric system thermal, voltage, and stability 
limits so that instability, uncontrolled separation, or cascading 
failures of such system will not occur as a result of a sudden 
disturbance, including a cybersecurity incident, or unanticipated 
failure of system elements.''
---------------------------------------------------------------------------

    459. Though MidAmerican urges the Commission to incorporate the 
definition of ``reliable operation'' into the pro forma OATT, other 
commenters argue that the definition of reliable operation should not 
be included in the pro forma OATT.\410\ Southern argues that the 
definition of reliable operation included in section 215 of the FPA 
would impose a higher standard on transmission providers than is 
currently required by well-established NERC standards. Southern and EEI 
assert that the system is not planned to be able to guarantee that 
operations will not be impaired under any conditions. Southern argues 
that transmission providers should not be held to a higher standard of 
having to ensure that the system can continue to be operated even if a 
``sudden disturbance, including a cybersecurity incident or 
unanticipated failure of system elements'' occurs.
---------------------------------------------------------------------------

    \410\ E.g., EEI, Powerex, Snohomish, Southern, Suez Energy NA, 
and TAPS.
---------------------------------------------------------------------------

    460. Along with Southern, EEI contends that the ERO should 
establish standards related to reliable operation. EEI states that 
section 215 of the FPA simply gives the Commission jurisdiction over 
reliability standards, which are defined as standards for the reliable 
operation of the transmission system; it does not require transmission 
providers to meet a ``reliable operation'' standard. This is an 
important distinction, EEI continues, because while a transmission 
provider may adopt reasonable reliability standards, that does not 
guarantee that it will in all instances meet a ``reliable operation'' 
requirement, which would require the transmission provider to in all 
instances prevent instability, uncontrolled separation or cascading 
failures despite sudden disturbances, cybersecurity incidents, or 
unanticipated failures of system elements. EEI and Southern contend 
that because the ERO will implement the directives of Congress 
contained in section 215, the ERO will be best suited to establish the 
reliability standards that incorporate principles of reliable 
operation.
    461. TAPS suggests that what is more important than adding a 
``reliable operation'' definition is making explicit in the tariff what 
the Commission stated in its Policy Statement on Matters Related to 
Bulk Power System Reliability (Reliability Policy Statement) \411\--
that transmission provider obligations under the pro forma OATT are 
subject to an overriding ``Good Utility Practice'' requirement that 
includes compliance with NERC reliability standards or more stringent 
regional reliability council standards.
---------------------------------------------------------------------------

    \411\ Policy Statement on Matters Related to Bulk Power System 
Reliability, 107 FERC ] 61,052 at P 23, clarified, 108 FERC ] 61,288 
(2004); Supplement to Policy Statement on Matters Related to Bulk 
Power System Reliability, 110 FERC ] 61,096 (2005).
---------------------------------------------------------------------------

Discussion
    462. We propose to require transmission-owning public utilities to 
modify the definition of Good Utility Practice in their respective 
OATTs to reference the reliable operation definition adopted in section 
215 of the FPA. We propose to take this action for two reasons. First, 
the Commission indicated in the Reliability Policy Statement that it 
expects public utilities operating transmission facilities under the 
pro forma OATT to conform to prevailing reliability standards. The 
Commission finds that referencing the reliable operation definition in 
section 215 of the FPA satisfies our requirement that transmission 
providers provide safe and reliable transmission service to customers 
taking service under the pro forma OATT. Second, we are mindful of the 
obligation placed on ``all users, owners and operators of the bulk 
power system'' under section 215(b) of the FPA to ``comply with 
reliability standards'' that will take effect under this section. Those 
reliability standards must ``provide for reliable operation of the 
bulk-power system.'' \412\ When the ERO is certified by the Commission 
and we approve its reliability standards, those standards will be based 
on the same definition of reliable operation we propose to incorporate 
into the pro forma OATT. We agree with EEI and Southern that the ERO is 
best suited to develop reliability standards for the Commission's 
approval, but our proposal to incorporate the definition of reliable 
operation does not establish a reliability standard; rather, we believe 
it reflects Congress's benchmark for acceptable utility practice. It 
therefore belongs in our definition of Good Utility Practice in the pro 
forma OATT.
---------------------------------------------------------------------------

    \412\ Section 215(a)(3) of the FPA.
---------------------------------------------------------------------------

    463. In addition to amending the definition of Good Utility 
Practice, we propose to add a definition for ``non-firm sales'' to 
clarify section 30.4 of the pro forma OATT. A number of transmission 
providers have modified section 30.4 of the OATT to state that ``The 
Network Customer shall not operate its designated Network Resources 
located in the Network

[[Page 32704]]

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'' 
(emphasis added). We propose to define ``non-firm sales'' as ``an 
energy sale for which delivery or receipt of the energy may be 
interrupted for any reason or for no reason, without liability on the 
part of either the buyer or seller.'' This is the definition of non-
firm sales used in a number of industry-standard master power sales 
agreements, including the EEI Master Purchase and Sale Agreement. We 
propose to clarify that, for the purposes of applying section 30.4 of 
the pro forma OATT, energy sales that can only be interrupted to 
maintain system reliability will be considered firm sales.
    464. We also propose to add two new definitions that are required 
to implement our proposed reforms. For example, we propose a definition 
of ``affiliate'' in section 1.1 of the revised pro forma OATT incident 
to our proposed change to the pricing of reassigned capacity. We also 
propose a new definition of ``pre-confirmed application'' in section 
1.40 of the revised pro forma OATT incident to our proposal to give 
priority to requests that are pre-confirmed.

E. Enforcement

1. General Policy
a. Compliance Review Regime
Comments
    465. A number of commenters indicate that a strong program to audit 
compliance with the pro forma OATT is crucial to preventing undue 
discrimination in the provision of transmission service. APPA argues 
that the Commission should establish a regime of systematic tariff 
compliance reviews because the OATT is at bottom a behavioral remedy 
rather than a structural one, so active Commission oversight is 
necessary. In addition, APPA notes that OATT transmission customers 
(especially network customers that are dependent upon the transmission 
systems of their neighboring public utility OATT transmission 
providers) are often reluctant to open the ``can of worms'' that filing 
a section 206 complaint against their transmission providers entails. 
Powerex urges the Commission to establish systematic tariff compliance 
audits as a monitoring tool because remedies and penalties alone are 
structurally ill-suited to address the myriad of idiosyncratic 
deviations from the Commission's policies and standards that currently 
exist. TAPS asserts that, while customer complaints are an indication 
that something is awry, the lack of transparency makes it very hard for 
customers to detect discrimination and tariff violations on the part of 
the transmission provider. TAPS suggests that customers often conclude 
that a complaint process is not cost effective because even if they 
ultimately prevail, they will have lost out on the purchase opportunity 
that prompted the complaint.
Discussion
    466. The Commission intends to maintain a strong audit program to 
determine whether transmission providers and transmission customers are 
in compliance with the new pro forma OATT. This audit program will 
include operational audits similar to the OATT compliance components of 
audits conducted by Commission staff in the past.
    467. These audits will determine compliance with specific 
provisions of the OATT. Staff's findings and recommendations will be 
detailed in public audit reports issued in accordance with the 
Commission's authority. If an audit is contested, it will be disposed 
of consistent with the Commission's final rule on disposition of 
contested operational audits. The Commission staff's compliance audits 
historically have included the collection of information regarding the 
audit target's overall operations. In this vein, the Commission staff's 
OATT compliance audits may also collect information regarding 
implementation of a transmission provider's OATT, with the intent that 
Commission staff may share the information it gathers with the 
Commission subject to all applicable ex parte rules.
b. Use of Independent Third Party Audits
Comments
    468. A number of commenters indicate that the Commission should not 
rely on third party audits as the primary means of ensuring compliance 
with the OATT. APPA states that if an OATT Transmission Provider 
retains and pays an ``independent reviewer'' to prepare compliance 
audit reports, someone will inevitably question the reviewer's 
independence. Therefore, APPA argues that it might be better for the 
Commission itself to prepare the reports, or to retain a consultant to 
do so. Southern suggests that the Commission's existing mechanisms, 
coupled with new rules that will ensure that all regulated entities 
subject to investigations or audits are afforded their full due process 
rights, should be adequate to ensure compliance with OATT provisions.
    469. A number of commenters also indicate that the Commission 
should require third party audits for frequent abusers. EEI suggests 
that a transmission provider that is found to have a systematic or 
continuing violation of the OATT could be required to hire an 
independent reviewer to monitor its future compliance for a period of 
time after the violation occurred. TVA suggests that, if a particular 
transmission provider repeatedly misapplies its OATT, the Commission 
should at that point consider requiring that transmission provider to 
hire an independent monitor for a defined period of time as a remedy 
for those actual infractions. NRECA argues that those transmission 
providers who are consistently in violation or who do not cure audit 
findings in a timely manner should see both an increase in frequency 
and further scrutiny from the audit process.
Discussion
    470. We propose to have Commission staff conduct audits of 
compliance with the new OATT. Commission staff is in a unique position 
to conduct OATT compliance audits and recommend remedial action 
consistent with previous audits. In addition, entities audited by 
Commission staff now have clear and assured due process rights as the 
result of Order No. 675.
    471. We may require third party audits as part of an individual 
compliance plan we order an audited party to undertake when we issue 
the Commission staff's audit report. The Commission staff monitors 
compliance with all of its audit recommendations as part of its regular 
practice. We may, in selected cases, decide to enhance this regular 
monitoring by requiring an audited party to hire an independent 
reviewer to continue compliance audits after the Commission staff's 
audit has ended. We could take such action in response to a number of 
circumstances, including, but not limited to, identification of 
systematic OATT violations, violations that require on-going 
monitoring, or a pattern of repeated OATT violations. Under these 
circumstances, the audited party should bear the burden of on-going 
compliance monitoring. If we decide to order independent OATT 
compliance audits as part of an individual audited party's compliance 
plan, we will specify the scope and duration of the audits.

[[Page 32705]]

2. Civil Penalties
a. Background
    472. The NOI observed that the existing OATT allows transmission 
providers to impose certain operational penalties on customers for 
tariff violations, but does not address the adverse consequences to a 
transmission provider who violates its OATT. It also summarized the 
broad variety of remedies and sanctions available for enforcement of 
its rules and regulations, including the enhanced civil penalty 
authority provided by EPAct 2005.\413\
---------------------------------------------------------------------------

    \413\ EPAct 2005 expanded the Commission's civil penalty 
authority under the FPA to encompass violations of all provisions of 
FPA Part II (EPAct 2005 section 1284(e)(1) (to be codified at 
section 316A of the FPA, 16 U.S.C. 825o-1)), and established the 
maximum civil penalty the Commission can assess under FPA Part II as 
$1 million per day per violation (EPAct 2005 section 1284(e)(2) (to 
be codified at section 316A of the FPA, 16 U.S.C. 825o-1)).
---------------------------------------------------------------------------

    473. In the NOI, the Commission asked for comments on whether we 
should address the issue of remedies or penalties against transmission 
providers as part of OATT reform. It also asked if transmission 
providers should be subject to revocation of their market-based rate 
authority for certain OATT violations, and if certain violatins should 
be considered market manipulation under the Market Behavior Rules \414\ 
and section 1283 of EPAct 2005.\415\
---------------------------------------------------------------------------

    \414\ Investigation of Terms and Conditions of Public Utility 
Market-Based Rate Authorizations, 105 FERC ] 61,218 (2003), order on 
reh'g, 107 FERC ] 61,175 (2004).
    \415\ NOI at P 15.
---------------------------------------------------------------------------

    474. Subsequent to the NOI, on October 20, 2005 the Commission 
issued its Enforcement Policy Statement, which discusses the factors 
the Commission will take into account in determining remedies and 
sanctions for violations, including civil penalties.\416\ Also, in 
EPAct 2005, Congress provided the Commission with specific anti-
manipulation authority.\417\ On January 19, 2006, to implement this new 
authority, the Commission issued Order No. 670 (Anti-manipulation 
Rule),\418\ adopting a new Part 1c of its regulations, under which it 
is ``unlawful for any entity, directly or indirectly, in connection 
with the purchase or sale of electric energy or the purchase or sale of 
transmission services subject to the jurisdiction of the Commission, 
(1) to use or employ any device, scheme, or artifice to defraud, (2) to 
make any untrue statement of a material fact or to omit to state a 
material fact necessary in order to make the statements made, in the 
light of the circumstances under which they were made, not misleading, 
or (3) to engage in any act, practice, or course of business that 
operates or would operate as a fraud or deceit upon any entity.'' \419\ 
The Anti-manipulation Rule made it unnecessary to retain Market 
Behavior Rules 2 or 6. Accordingly, on February 16, 2006, the 
Commission rescinded Market Behavior Rules 2 and 6 and codified the 
substance of Market Behavior Rules 1, 3, 4, and 5 in the Commission's 
regulations.\420\
---------------------------------------------------------------------------

    \416\ Enforcement of Statutes, Order, Rules and Regulations, 
Policy Statement on Enforcement, 113 FERC ] 61,068 at P 17-20 (2005) 
(Enforcement Policy Statement).
    \417\ EPAct 2005 sec. 1283 (to be codified at section 222 of the 
FPA, 16 U.S.C. 824v). Congress prohibited the use or employment of 
``any manipulative or deceptive device or contrivance'' in 
connection with the purchase or sale of electric energy or 
transmission services subject to the jurisdiction of the Commission. 
Congress directed the Commission to give these terms the same 
meaning as under the Securities Exchange Act of 1934, 15 U.S.C. 
78j(b) (2000).
    \418\ Prohibition of Energy Market Manipulation, Order No. 670, 
71 FR 4244 (Jan. 26, 2006), FERC Stats. & Regs. ] 31,202, reh'g 
denied, 114 FERC ] 61,300 (2006).
    \419\ Id., 71 FR 4244, 4258 (Jan. 26, 2006) (to be codified at 
18 CFR 1c.2(a)).
    \420\ Investigation of Terms and Conditions of Public Utility 
Market-Based Rate Authorizations, 114 FERC ] 61,165 (2005). The 
primary purpose of the Market Behavior Rules was to prohibit market 
manipulation by public utility sellers acting under market-based 
rate authority.
---------------------------------------------------------------------------

b. Whether Civil Penalties Should Be Specified in the OATT
Comments
    475. Commenters often did not distinguish between operational 
penalties and civil penalties in their comments about the need for 
additional penalties in the OATT. EEI and MidAmerican made the 
distinction, asserting that civil penalties should not be specified in 
the OATT. They and others contend that: enforcement actions, including 
civil penalties, should be reviewed on a case-by-case basis; \421\ 
civil penalties should be based upon the seriousness of the violation; 
\422\ penalties should require proof of intent or willfulness; \423\ 
penalties should only apply for repeated violations; \424\ and, penalty 
procedures should provide for due process.\425\
---------------------------------------------------------------------------

    \421\ E.g., Entergy, Santa Clara, Steel Manufacturers 
Association, WAPA, and Williams.
    \422\ Steel Manufacturers Association.
    \423\ E.g., EEI, KCP&L, Progress Energy, Public Power Council, 
Southern, and Xcel.
    \424\ E.g., Alberta Intervenors, Public Power Council, 
Snohomish, Suez Energy NA, and TDU Systems.
    \425\ E.g., Bonneville, EEI, Southern, and Nevada Companies.
---------------------------------------------------------------------------

Discussion
    476. The Commission intends to enforce OATT provisions in a firm 
but fair manner. For example, the Commission elsewhere is proposing 
that transmission providers as well as transmission customers be 
subject to specified operational penalties for violations of certain 
OATT provisions. However, aside from these operational penalties, the 
Commission does not intend to provide a schedule of enforcement 
remedies and sanctions in the OATT. Instead, the Commission prefers to 
examine violations and determine the appropriate response for a 
violation on a case-by-case basis. The Commission has a broad array of 
equitable remedies and sanctions for violations.\426\ Our enhanced 
civil penalties, as provided by EPAct 2005, are among the available 
sanctions for violations of the Commission's statutes, rules, 
regulations and orders, including instances of undue discrimination and 
market manipulation.
---------------------------------------------------------------------------

    \426\ Enforcement Policy Statement at P 4. The ``enhanced civil 
penalty authority will operate in tandem with our existing authority 
to require disgorgement of unjust profits obtained through 
misconduct and/or to condition, suspend, or revoke certificate 
authority or other authorizations, such as market-based rate 
authority for sellers of electric energy.'' Id. at P 12.
---------------------------------------------------------------------------

    477. Although we will look at violations on a case-by-case basis 
and not identify in this proposed rule specific penalties for different 
violations, the Enforcement Policy Statement provides guidance and 
regulatory certainty regarding enforcement and places entities subject 
to our jurisdiction on notice of the consequences of violations.\427\ 
As we noted, ``[I]t is important that we retain the discretion and 
flexibility to address each case on its merits, and to fashion remedies 
appropriate to the facts presented, including any mitigating factors.'' 
\428\
---------------------------------------------------------------------------

    \427\ Id. at P 1.
    \428\ Id. at P 13. Several commenters supported the application 
of the Enforcement Policy Statement to OATT violations. E.g., APPA, 
EEI, Midwest SATs, National Grid, and TAPS.
---------------------------------------------------------------------------

    478. As the facts of a specific matter warrant, we will seek 
disgorgement of unjust profits that are the result of a violation. 
Violators should not retain the gains acquired as the result of the 
violation. OATT violators will be expected to disgorge unjust profits 
whenever they can be determined or reasonably estimated.\429\ In 
addition, as warranted by the facts, civil penalties may also be 
assessed. Those penalties (up to $1 million per day per violation), 
however, can be mitigated by the factors set forth in the Enforcement 
Policy Statement, such as self-reporting, compliance programs, and 
cooperation

[[Page 32706]]

with staff from the Commission's Office of Enforcement.\430\
---------------------------------------------------------------------------

    \429\ Enforcement Policy Statement at P 19 and P 23.
    \430\ Id. at P 6 and P 21-27.
---------------------------------------------------------------------------

c. Whether Transmission Providers Should Be Subject to Revocation of 
Their Market-Based Rates for OATT Violations.
Comments
    479. In the NOI, the Commission also asked if transmission 
providers should be subject to revocation of their market-based rate 
authority for certain OATT violations.\431\ Some commenters agree that 
revocation of market-based rates could be an appropriate remedy.\432\ 
EPSA asserts that revocation of market-based rate authority should be 
among the penalties the Commission could impose for serious violations 
of the OATT, such as when more transmission capacity is set aside than 
is actually needed to serve native load, or undue preferences are 
extended to native load or affiliate transactions. TAPS states that 
where lack of ATC forecloses network customer access to alternatives, a 
transmission provider should not be able to make sales of electric 
power at market-based rates and should be required to offer embedded-
cost-based sales. APPA asserts that whether a transmission provider's 
violation of the OATT merits possible revocation of its market-based 
rate authority depends on the nature and severity of the violation. 
APPA argues that if the violation concerns practices that favor the 
transmission provider's own wholesale merchant function at the expense 
of its third-party competitors, and if that violation is willful or 
repeated, then revocation or conditioning of the market-based rate 
authority of the transmission provider's merchant function may be 
warranted.\433\
---------------------------------------------------------------------------

    \431\ NOI at P 15.
    \432\ E.g., Arkansas Cities, NRECA, Occidental, Snohomish, and 
Williams.
    \433\ APPA at 32.
---------------------------------------------------------------------------

    480. Other commenters argue that revocation of market-based rate 
authority should be reserved for market behavior violations, not OATT 
violations.\434\ EEI and MidAmerican argue that the Commission has 
separated public utilities' transmission functions from their marketing 
functions and, thus, penalties for violation of the OATT should be kept 
separate from penalties imposed for market behavior violations. 
PacifiCorp contends that the Commission's new penalty authority is 
sufficient to ensure compliance with the OATT and that there no longer 
is a need to consider revocation of market-based rate authority. 
Progress Energy states that the Commission should not penalize the 
utility's merchant function for violations of the OATT caused by the 
utility's transmission function. Ameren and Southern would add a 
``willful'' or ``intent'' requirement to revoking market-based rates 
for an OATT violation.
---------------------------------------------------------------------------

    \434\ E.g., EEI, MidAmerican, PacifiCorp, PNM-TNMP, and Progress 
Energy.
---------------------------------------------------------------------------

Discussion

    481. As discussed in the Enforcement Policy Statement, the better 
approach is to look at all of the facts and circumstances of each 
violation before deciding on any remedy or sanction.\435\ There may be 
OATT violations in circumstances that, after applying the factors in 
the Enforcement Policy Statement, merit revocation or limitation of 
market-based rate authority. However, before the Commission will 
consider revoking an entity's market-based rate authority for a 
violation of the OATT, there must be a nexus between the specific facts 
relating to the OATT violation and the entity's market-based rate 
authority. The Commission proposes that if it determines, as a result 
of a significant OATT violation, that the market-based rate authority 
of a transmission provider will be revoked within a particular market, 
each affiliate of the transmission provider that possesses market-based 
rate authority will have it revoked in that market on the effective 
date of revocation of the transmission provider's market-based rate 
authority.
---------------------------------------------------------------------------

    \435\ Enforcement Policy Statement at P 18. Among the factors 
examined are ``willfulness'' and ``intent'' of the violator. Id. at 
P 20.
---------------------------------------------------------------------------

d. Whether Certain OATT Violations Should Be Considered Market 
Manipulation Under the Market Behavior Rules and Section 1283 of EPAct 
2005.
Comments
    482. In the NOI, the Commission asked if specific OATT violations 
should be considered market manipulation under the Market Behavior 
Rules and section 1283 of EPAct 2005.\436\ The Commission then 
suggested that one such type of violation might be when a transmission 
provider sets aside more transmission capacity than is needed to serve 
native load, but uses the capacity for third-party sales.\437\
---------------------------------------------------------------------------

    \436\ NOI at P 15. Section 1283 of EPAct 2005 establishes 
section 222 of the FPA (to be codified at 16 U.S.C. 824v).
    \437\ NOI at P 15.
---------------------------------------------------------------------------

    483. None of the commenters want specific violations identified in 
the OATT to be deemed per se market manipulation. Some commenters 
prefer to have the Commission approach these matters on case-by-case 
basis.\438\
---------------------------------------------------------------------------

    \438\ E.g., APPA, Entergy, Nevada Companies, Public Power 
Council, and Southern.
---------------------------------------------------------------------------

    484. Some commenters, like Constellation, identify OATT violations 
that may constitute market manipulation. Ameren, EEI, and Occidental 
argue that intentionally setting aside more transmission capacity than 
is needed to serve native load could constitute market manipulation. 
LG&E states that the key factor is ``intent.'' LG&E provides an example 
in which ATC becomes available as a result of less-than-expected native 
load requirements, and not because the transmission owner intentionally 
overstated native load requirements, and the transmission owner's 
affiliate followed proper reservation and scheduling protocol in a 
manner applicable to all potential transmission customers. Under these 
circumstances, LG&E contends, the Commission's imposition of a civil 
penalty would be inappropriate given the absence of intent to impart 
false or misleading information into the marketplace or hoard 
transmission.
    485. Occidental suggests that curtailments of firm transmission 
service designed to permit wholesale power sales by the merchant 
function of the transmission provider or an affiliate should also be 
considered market manipulation. Suez Energy NA argues that incidents of 
affiliate abuse by a transmission provider may be considered market 
manipulation pursuant to section 1283 of EPAct 2005. TAPS states that 
certain withholding of transmission capacity can rise to the level of a 
violation of the Commission's market behavior rules and its new anti-
manipulation authority if the withholding reduces the supply of both 
transmission and generation in a market, which artificially raises 
prices.
Discussion
    486. As explained above, we now are examining market manipulation 
in the context of Part 1c of our regulations. We do not propose to 
identify in the OATT specific conduct as per se market manipulation. As 
noted in Order No. 670, market manipulation is a fact-intensive 
determination.\439\ We do not want to restrict our fact-finding to 
specific types of violations. Although certain fraudulent or deceptive 
practices concerning the OATT could qualify as market manipulation 
under Order No. 670, the Commission declines to address such 
circumstances generically

[[Page 32707]]

in this rulemaking and instead will consider them on a case-by-case 
basis, if and when they arise, under the standards set forth in Order 
No. 670.
---------------------------------------------------------------------------

    \439\ Anti-manipulation Rule at P 72.
---------------------------------------------------------------------------

VI. Information Collection Statement

    487. The following collections of information contained in this 
proposed rule have been submitted to the Office of Management and 
Budget (OMB) for review under section 3507(d) of the Paperwork 
Reduction Act of 1995.\440\ OMB's regulations require OMB to approve 
certain information collection requirements imposed by agency 
rule.\441\
---------------------------------------------------------------------------

    \440\ 44 U.S.C. 3507(d) (2000).
    \441\ 5 CFR 1320.11 (2005).
---------------------------------------------------------------------------

    488. Comments are solicited on the need for this information, 
whether the information will have practical utility, ways to enhance 
the quality, utility, and clarity of the information to be collected, 
and any suggested methods for minimizing respondents' burden, including 
the use of automated information techniques.
    Burden Estimate: The public reporting and records retention burdens 
for the proposed reporting requirements and the records retention 
requirement are as follows.\442\
---------------------------------------------------------------------------

    \442\ These burden estimates apply only to this NOPR and do not 
reflect upon all of FERC-516 or FERC-717.

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
Part 35 (FERC-516):
Conforming tariff changes.......................             176               1              25           4,400
Revision of Imbalance Charges...................             176               1               5             880
ATC revisions...................................             176               1              40           7,040
Planning (Attachment K).........................             176               1             100          17,600
Congestion studies..............................             176               1             250          44,000
Attestation of network resource commitment......             176               1               1             176
Quarterly Reports for capacity reassignment.....             176               1              60          10,560
Operational Penalty annual filing...............             176               1              10           1,760
Creditworthiness--include criteria in the tariff             176               1              40           7,040
¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤
    Sub Total Part 35...........................  ..............  ..............  ..............          93,456
Part 37 (FERC-717):
ATC-related standards...........................
NERC/NAESB Team to develop......................               1               1           1,920           1,920
Review and comment by utility...................             176               1              20           3,520
Implementation by each utility..................             176               1              40           7,040
Mandatory data exchanges........................             176               1              80          14,080
Explanation of change of ATC values.............             176               1             100          17,600
Reevaluate CBM and post quarterly...............             176               1              20           3,520
Post OASIS metrics; requests accepted/denied....             176               1              80          14,080
Posting of metrics for System Impact Studies....             176               1             100          17,600
Post all rules to OASIS.........................             176               1               5             880
¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤
    Sub Total (Part 37).........................  ..............  ..............  ..............          80,240
¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤
        Total (Part 35 + Part 37)...............  ..............  ..............  ..............         173,696
¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤¤
Recordkeeping...................................             176               1              30           5,280
----------------------------------------------------------------------------------------------------------------

Total Annual Hours for Collection:
    Reporting + recordkeeping hours = 173,696 + 5,280 = 178,976 hours.
Cost to Comply:
Reporting = $19,801,344
hour), consultant ($150), technical ($80), and administrative support 
($25))
Recordkeeping = $1,392,160
$89,760
$1,302,400
Total costs = $21,193,504
    Labor $ ($19,801,344 + $89,760) + Recordkeeping Storage Costs 
($1,302,400)
    OMB's regulations require it to approve certain information 
collection requirements imposed by an agency rule. The Commission is 
submitting notification of this proposed rule to OMB. If the proposed 
requirements are adopted they will be mandatory requirements.
    Title: FERC-516, Electric Rate Schedules and Tariff Filings; FERC-
717 Standards for Business Practices and Communication Protocols for 
Public Utilities.
    Action: Proposed Collections.
    OMB Control Nos. 1902-0096 and 1902-0173.
    Respondents: Business or other for profit.
    Frequency of responses: On occasion.
    Necessity of the Information:
    489. The Federal Energy Regulatory Commission is proposing 
amendments to its regulations adopted in Order Nos. 888 and 889, and to 
the pro forma open access transmission tariff, to ensure that 
transmission services are provided on a basis that is just, reasonable 
and not unduly discriminatory or preferential. The purpose of this 
rulemaking is to strengthen the pro forma OATT to ensure that it 
achieves its original purpose--remedying undue discrimination--not to 
create new market structures. We propose to achieve this goal by 
increasing the clarity and transparency of the rules applicable to the 
planning and use of the transmission system and by addressing 
ambiguities and the lack of sufficient detail in several important 
areas of the pro forma OATT. The lack of specificity in the pro forma 
OATT creates opportunities for undue discrimination as well as making 
the undue discrimination that does occur more difficult to detect. To 
accomplish this we are proposing five objectives: (1) To improve 
transparency and

[[Page 32708]]

consistency in several critical areas, by providing for greater 
consistency in the calculation of ATC, (2) to reform the transmission 
planning requirements of the pro forma OATT to eliminate potential 
undue discrimination and support the construction of adequate 
transmission facilities to meet the needs of all load-serving entities, 
(3) to remedy certain portions of the pro forma OATT that may have 
permitted utilities to discriminate against new merchant generation, 
including intermittent generation, (4) to provide for greater 
transparency in the provision of transmission service to allow 
transmission customers better access to information to make their 
resource procurement and investment decisions, as well as to increase 
the Commission's ability to detect any remaining incidents of undue 
discrimination, and (5) to reform and provide greater clarity in areas 
that have generated recurring disputes over the past 10 years, such as 
rollover rights, ``redirects,'' and generation redispatch. The reforms 
proposed in this NOPR are intended to address deficiencies in the pro 
forma OATT that have become apparent since the implementation of Order 
No. 888 in 1996 and to facilitate improved planning and operation of 
transmission facilities.
    490. Interested persons may obtain information on the reporting 
requirements by contacting the following: Federal Energy Regulatory 
Commission, 888 First Street, NE., Washington, DC 20426, [Attention: 
Michael Miller, Office of the Executive Director, Phone: (202) 502-
8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov.]
    491. For submitting comments concerning the collections of 
information and the associated burden estimate(s), please send your 
comments to the contact listed above and to the Office of Information 
and Regulatory Affairs, Office of Management and Budget, 725 17th 
Street, NW., Washington, DC 20503 [Attention: Desk Officer for the 
Federal Energy Regulatory Commission, phone (202) 395-4650, fax: (202) 
395-7285. Due to security concerns, comments should be sent 
electronically to the following e-mail address: 
oira_submission@omb.eop.gov. Please reference the docket number of this 

rulemaking in your submission.

VII. Environmental Analysis

    492. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\443\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this NOPR under section 
380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale subject to the Commission's 
jurisdiction, plus the classification, practices, contracts and 
regulations that affect rates, charges, classifications and 
services.\444\
---------------------------------------------------------------------------

    \443\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 
] 30,783 (1987).
    \444\ 18 CFR 380.4(a)(15) (2005).
---------------------------------------------------------------------------

VIII. Regulatory Flexibility Act Analysis

    493. The Regulatory Flexibility Act of 1980 (RFA) \445\ generally 
requires a description and analysis of proposed rules that will have 
significant economic impact on a substantial number of small entities. 
This rule applies to public utilities that own, control or operate 
interstate transmission facilities, not to electric utilities per se. 
The total number of public utilities that, absent waiver, would have to 
modify their current OATTs by filing the revised pro forma OATT is 
176.\446\ Of these only six public utilities, or less than two percent, 
dispose of four million MWh or less per year.\447\ The Commission does 
not consider this a substantial number, and in any event, these small 
entities may seek waiver of these requirements.\448\ Moreover, the 
criteria for waiver that would be applied under this rulemaking for 
small entities is unchanged from that used to evaluate requests for 
waiver under Order Nos. 888 and 889. Thus, small entities who have 
received waiver of the requirements to have on file an open access 
tariff or to operate an OASIS would be unaffected by the requirements 
of this proposed rulemaking.
---------------------------------------------------------------------------

    \445\ 5 U.S.C. 601-612 (2000).
    \446\ The sources for this figure are FERC Form No. 1 and FERC 
Form No. 1-F data.
    \447\ Id.
    \448\ The Regulatory Flexibility Act defines a ``small entity'' 
as ``one which is independently owned and operated and which is not 
dominant in its field of operation.'' See 5 U.S.C. 601(3) and 
601(6)(2000); 15 U.S.C. 632(a)(1)(2000). In Mid-Tex Elec. Coop. v. 
FERC, 773 F.2d 327, 340-343 (D.C. Cir. 1985), the court accepted the 
Commission's conclusion that, since virtually all of the public 
utilities that it regulates do not fall within the meaning of the 
term ``small entities'' as defined in the Regulatory Flexibility 
Act, the Commission did not need to prepare a regulatory flexibility 
analysis in connection with its proposed rule governing the 
allocation of costs for construction work in progress (CWIP). The 
CWIP rules applied to all public utilities. The revised pro forma 
OATT will apply only to those public utilities that own, control or 
operate interstate transmission facilities. These entities are a 
subset of the group of public utilities found not to require 
preparation of a regulatory flexibility analysis for the CWIP rule.
---------------------------------------------------------------------------

IX. Comment Procedures

    494. The Commission invites interested persons to submit comments 
on the matters and issues proposed in this notice to be adopted, 
including any related matters or alternative proposals that commenters 
may wish to discuss. Comments are due August 7, 2006. Reply comments 
are due September 5, 2006. Comments must refer to Docket Nos. RM05-25-
000 and RM05-17-000, and must include the commenters' name, the 
organization they represent, if applicable, and their address in their 
comments. Comments may be filed either in electronic or paper format.
    495. To facilitate the Commission's review of the comments, 
commenters are requested to provide an executive summary of their 
position, not to exceed ten pages. Commenters are requested to identify 
each section of the NOPR that their discussion addresses and to use 
conforming headings. Additional issues the commenters wish to raise 
should be clearly identified in a separate section entitled ``Other 
Issues,'' which should be organized by the relevant pro forma OATT 
section (if applicable). Furthermore, we also request that commenters 
with specific tariff language suggestions submit a redline/strikeout 
version showing their proposed changes to the language that appears in 
the pro forma OATT attached to this NOPR.\449\ The commenters should 
double space their comments. To assist commenters in their review, the 
Commission has posted a copy of the proposed revised pro forma OATT 
with changes from the current version of the pro forma OATT shown in 
redline/strikeout on the following location on our Web site at http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp
.

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

    \449\ The pro forma OATT includes two amendments that have been 
made since the tariff was finalized in Order No. 888-B. First, the 
tariff was amended to include protocols for curtailment of multi-
system transactions and parallel flows. See North American 
Reliability Council, 85 FERC ] 61,353 (1998), reh'g denied, 87 FERC 
] 61,161 (1999) and recently updated in North American Electric 
Reliability Council, 110 FERC ] 61,388 (2005). The second amendment 
incorporates standardized generator interconnection procedures. See 
Order No. 2003. The standardized generator interconnection 
procedures are not included in the pro forma OATT attached to this 
NOPR because we do not propose changes to them.
---------------------------------------------------------------------------

    496. Comments and reply comments may be filed electronically via 
the

[[Page 32709]]

eFiling link on the Commission's Web site at http://www.ferc.gov. The 

Commission accepts most standard word processing formats and commenters 
may attach additional files with supporting information in certain 
other file formats. Documents created electronically using word 
processing software should be filed in the native application or print-
to-PDF format and not in a scanned format. This will enhance document 
retrieval for both the Commission and the public. Attachments that 
exist only in paper form may be scanned. Commenters filing 
electronically should not make a paper filing. Service of rulemaking 
comments is not required. Commenters that are not able to file comments 
electronically must send an original and 14 copies of their comments 
to: Federal Energy Regulatory Commission, Office of the Secretary, 888 
First Street, NE., Washington, DC 20426.
    497. All comments will be placed in the Commission's public files 
and may be viewed, printed, or downloaded remotely as described in the 
Document Availability section below. Commenters on this proposal are 
not required to serve copies of their comments on other commenters.

X. Document Availability

    498. 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 the Commission's Home Page (http://www.ferc.gov) and 

in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, 
Washington DC 20426.
    499. From the Commission's Home Page on the Internet, this 
information is available in the Commission's document management 
system, 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 ``RM05-25'' or 
``RM05-17'' in the docket number field.
    500. User assistance is available for eLibrary and the Commission's 
website during normal business hours. For assistance, please contact 
the Commission's Online Support at 1-866-208-3676 (toll free) or 202-
502-6652 (e-mail at FERCOnlineSupport@FERC.gov), or the Public 
Reference Room at 202-502-8371, TTY 202-502-8659 (e-mail at 
public.referenceroom@ferc.gov).

List of Subjects

18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

18 CFR Part 37

    Conflict of interests, Electric power plants, Electric utilities, 
Reporting and recordkeeping requirements.

    By direction of the Commission.
Magalie R. Salas,
Secretary.

    In consideration of the foregoing, the Commission proposes to amend 
parts 35 and 37, Chapter I, Title 18 of the Code of Federal 
Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

    1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 71-7352.

    2. Amend Sec.  35.28 as follows:
    a. paragraph (c) is revised.
    b. paragraphs (d)(i) and d(ii) are redesignated as d(1) and d(2).
    c. newly redesignated paragraph d(1) is revised.
    d. paragraph (e)(1) (introductory text) is revised.
    e. paragraph (e)(1)(ii) is revised.

Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (c) Non-discriminatory open access transmission tariffs.
    (1) Every public utility that owns, controls, or operates 
facilities used for the transmission of electric energy in interstate 
commerce must have on file with the Commission a tariff of general 
applicability for transmission services, including ancillary services, 
over such facilities. Such tariff must be the open access pro forma 
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as 
revised by the open access pro forma tariff contained in Order No. ----
, FERC Stats. & Regs. ] ----, or such other open access tariff as may 
be approved by the Commission consistent with Order No. ----, FERC 
Stats. & Regs. ] ----.
    (i) Subject to the exceptions in paragraphs (c)(1)(ii), 
(c)(1)(iii), (c)(1)(iv) and (c)(1)(v) of this section, the pro forma 
tariff contained in Order No. 888, FERC Stats. & Regs. ]31,036, as 
revised by the open access pro forma tariff contained in Order No. ----
, FERC Stats. & Regs. ] ----, and accompanying rates, must be filed no 
later than 60 days prior to the date on which a public utility would 
engage in a sale of electric energy at wholesale in interstate commerce 
or in the transmission of electric energy in interstate commerce.
    (ii) If a public utility owns, controls, or operates facilities 
used for the transmission of electric energy in interstate commerce as 
of ----, it must file the revisions to the pro forma tariff contained 
in Order No. ----, FERC Stats. & Regs. ] ---- pursuant to section 206 
of the FPA and accompanying rates pursuant to section 205 of the FPA, 
no later than ----.
    (iii) If a public utility owns, controls, or operates transmission 
facilities used for the transmission of electric energy in interstate 
commerce as of ----, such facilities are jointly owned with a non-
public utility, and the joint ownership contract prohibits transmission 
service over the facilities to third parties, the public utility with 
respect to access over the public utility's share of the jointly owned 
facilities must file no later than ---- the revisions to the pro forma 
tariff contained in Order No. ----, FERC Stats. & Regs. ] ----, 
pursuant to section 206 of the FPA and accompanying rates pursuant to 
section 205 of the FPA.
    (iv) Any public utility whose transmission facilities are under the 
independent control of a Commission-approved ISO or RTO may satisfy its 
obligation under paragraph (c)(1) of this section, with respect to such 
facilities, through the open access transmission tariff filed by the 
ISO or RTO.
    (v) If a public utility obtains a waiver of the tariff requirement 
pursuant to paragraph (d) of this section, it does not need to file the 
pro forma tariff required by this section.
    (vi) Any public utility that seeks a deviation from the pro forma 
tariff contained in Order No. 888, FERC Stats. & Regs. ]31,036, as 
revised in Order No. ----, FERC Stats. & Regs. ] ----, must demonstrate 
that the deviation is consistent with the principles of Order No., ---- 
FERC Stats. & Regs. ] ----.
    (vii) Each public utility's open access transmission tariff must 
include the standards incorporated by reference in part 38 of this 
chapter.
    (2) Subject to the exceptions in paragraphs (c)(2)(i) and 
(c)(3)(iii) of this section, every public utility that owns, controls, 
or operates facilities used for the transmission of electric energy in 
interstate commerce, and that uses those facilities to engage in 
wholesale sales and/or purchases of electric energy, or unbundled 
retail sales of electric energy, must take transmission service for 
such sales and/or purchases under the open access tariff filed pursuant 
to this section.

[[Page 32710]]

    (i) For sales of electric energy pursuant to a requirements service 
agreement executed on or before July 9, 1996, this requirement will not 
apply unless separately ordered by the Commission. For sales of 
electric energy pursuant to a bilateral economy energy coordination 
agreement executed on or before July 9, 1996, this requirement is 
effective on December 31, 1996. For sales of electric energy pursuant 
to a bilateral non-economy energy coordination agreement executed on or 
before July 9, 1996, this requirement will not apply unless separately 
ordered by the Commission.
    (ii) [Reserved.]
    (3) Every public utility that owns, controls, or operates 
facilities used for the transmission of electric energy in interstate 
commerce, and that is a member of a power pool, public utility holding 
company, or other multi-lateral trading arrangement or agreement that 
contains transmission rates, terms or conditions, must have on file a 
joint pool-wide or system-wide open access transmission pro forma 
tariff, which tariff must be the open access pro forma tariff contained 
in Order No. 888, FERC Stats. & Regs. ] 31,036, as revised by the open 
access pro forma tariff contained in Order No. ----, FERC Stats. & 
Regs. ] ----, or such other open access tariff as may be approved by 
the Commission consistent with Order No. ----, FERC Stats. & Regs. ] --
--.
    (i) For any power pool, public utility holding company or other 
multi-lateral arrangement or agreement that contains transmission 
rates, terms or conditions and that is executed after July 9, 1996, 
this requirement is effective on the date that transactions begin under 
the arrangement or agreement.
    (ii) For any power pool, public utility holding company or other 
multi-lateral arrangement or agreement that contains transmission 
rates, terms or conditions and that is executed on or before July 9, 
1996, a public utility member of such power pool, public utility 
holding company or other multi-lateral arrangement or agreement that 
owns, controls, or operates facilities used for the transmission of 
electric energy in interstate commerce must file the revisions to its 
joint pool-wide or system-wide contained in Order No. ----, FERC Stats. 
& Regs. ] ----, pursuant to section 206 of the FPA and accompanying 
rates pursuant to section 205 of the FPA, no later than ----.
    (iii) A public utility member of a power pool, public utility 
holding company or other multi-lateral arrangement or agreement that 
contains transmission rates, terms or conditions and that is executed 
on or before July 9, 1996 must take transmission service under a joint 
pool-wide or system-wide pro forma tariff filed pursuant to this 
section for wholesale trades among the pool or system members.
    (4) Consistent with paragraph (c)(1) of this section, every 
Commission-approved ISO or RTO must have on file with the Commission a 
tariff of general applicability for transmission services, including 
ancillary services, over such facilities. Such tariff must be the open 
access pro forma tariff contained in Order No. 888, FERC Stats. & Regs. 
] 31,036, as revised by the open access pro forma tariff contained in 
Order No. ----, FERC Stats. & Regs. ] ----, or such other open access 
tariff as may be approved by the Commission consistent with Order No. 
----, FERC Stats. & Regs. ] ----.
    (i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to the pro forma tariff 
contained in Order No. ----, FERC Stats. & Regs. ] ----, pursuant to 
section 206 of the FPA and accompanying rates pursuant to section 205 
of the FPA, no later than ----.
    (ii) If a Commission-approved ISO or RTO can demonstrate that its 
existing open access tariff is consistent with or superior to the 
revisions to the pro forma tariff contained in Order No. ----, FERC 
Stats. & Regs. ] ----, or any portions thereof, the Commission-approved 
ISO or RTO may instead set forth such demonstration in its filing 
pursuant to section 206 no later than ----.
    (d) Waivers. * * *
    (1) No later than ----, or
* * * * *
    (e) Non-public utility procedures for tariff reciprocity 
compliance. (1) A non-public utility may submit a transmission tariff 
and a request for declaratory order that its voluntary transmission 
tariff meets the requirements of Order No. 888, FERC Stats. & Regs. ] 
31,036 and Order No. ----, FERC Stats. & Regs. ] ----.
    (i) * * *
    (ii) If the submittal is found to be an acceptable transmission 
tariff, an applicant in a Federal Power Act (FPA) section 211 or 211A 
proceeding against the non-public utility shall have the burden of 
proof to show why service under the open access tariff is not 
sufficient and why a section 211 or 211A order should be granted.
* * * * *

PART 37--OPEN ACCESS SAME-TIME INFORMATION SYSTEMS

    3. 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.

    4. Amend Sec.  37.6 as follows:
    a. paragraph (a)(1) is revised.
    b. paragraph (b)(introductory text) is revised.
    c. paragraphs (b)(1)(v) through (b)(1)(viii) are added.
    d. paragraphs (b)(2)(i) and b(2)(ii) are revised.
    e. paragraph (b)(3) is revised.
    f. paragraph (c)(2) is revised.
    g. paragraphs (e)(1) and (e)(2)(ii) are revised.
    h. paragraph (e)(3)(ii) is revised.
    i. paragraphs (h) and (i) are added.

Sec.  37.6  Information to be posted on the OASIS.

    (a) * * *
    (1) Make requests for transmission services offered by Transmission 
Providers, Resellers and other providers of ancillary services, request 
the designation of a network resource, and request the termination of 
the designation of a network resource;
* * * * *
    (b) Posting transfer capability. The available transfer capability 
on the Transmission Provider's system (ATC) and the total transfer 
capability (TTC) of that system shall be calculated and posted for each 
Posted Path as set out in this section.
    (1) * * *
    (v) Available transfer capability or ATC means the transfer 
capability remaining in the physical transmission network for further 
commercial activity over and above already committed uses, or such 
definition as contained in Commission-approved Reliability Standards.
    (vi) Total transfer capability or TTC means the amount of electric 
power that can be moved or transferred reliably from one area to 
another area of the interconnected transmission systems by way of all 
transmission lines (or paths) between those areas under specified 
system conditions, or such definition as contained in Commission-
approved Reliability Standards.
    (vii) Capacity Benefit Margin or CBM means the amount of TTC 
preserved by the Transmission Provider for load-serving entities, whose 
loads are located on that Transmission Provider's system, to enable 
access by the load-serving entities to generation from interconnected 
systems to meet generation reliability requirements, or such definition 
as contained in Commission-approved Reliability Standards.
    (viii) Transmission Reliability Margin or TRM means the amount of 
TTC necessary to provide reasonable

[[Page 32711]]

assurance that the interconnected transmission network will be secure, 
or such definition as contained in Commission-approved Reliability 
Standards.
    (2) * * *
    (i) Information used to calculate any posting of ATC and TTC must 
be dated and time-stamped and all calculations shall be performed 
according to consistently applied methodologies referenced in the 
Transmission Provider's transmission tariff and shall be based on 
Commission-approved Reliability Standards as well as current industry 
practices, standards and criteria
    (ii) On request, the Responsible Party must make all data used to 
calculate ATC, TTC, CBM, and TRM for any constrained posted paths 
publicly available (including the limiting element(s) and the cause of 
the limit (e.g., thermal, voltage, stability)) in electronic form 
within one week of the posting. The information is required to be 
provided only in the electronic format in which it was created, along 
with any necessary decoding instructions, at a cost limited to the cost 
of reproducing the material. This information is to be retained for six 
months after the applicable posting period.
* * * * *
    (3) Posting. The ATC, TTC, CBM, and TRM for all Posted Paths must 
be posted in megawatts by specific direction and in the manner 
prescribed in this subsection.
    (i) Constrained posted paths--(A) For Firm ATC and TTC. (1) The 
posting shall show ATC, TTC, CBM, and TRM for a 30-day period. For this 
period postings shall be: By the hour, for the current hour and the 168 
hours next following; and thereafter, by the day. If the Transmission 
Provider charges separately for on-peak and off-peak periods in its 
tariff, ATC, TTC, CBM, and TRM will be posted daily for each period.
    (2) Postings shall also be made by the month, showing for the 
current month and the 12 months next following.
    (3) If planning and specific requested transmission studies have 
been done, seasonal capability shall be posted for the year following 
the current year and for each year following to the end of the planning 
horizon but not to exceed 10 years.
    (B) For Non-Firm ATC and TTC. The posting shall show ATC, TTC, CBM 
and TRM for a 30-day period by the hour and days prescribed under 
paragraph (b)(3)(i)(A)(1) of this section and, if so requested, by the 
month and year as prescribed under paragraph (b)(3)(i)(A) (2) and (3) 
of this section. The posting of non-firm ATC and TTC shall show CBM as 
zero.
    (C) Updating Posted Information for Constrained Paths. (1) The 
capability posted under paragraphs (b)(3)(i) (A) and (B) of this 
section must be updated when transactions are reserved or service ends 
or whenever the TTC estimate for the Path changes by more than 10 
percent.
    (2) All updating of hourly information shall be made on the hour.
    (3) When the monthly and yearly capability posted under paragraphs 
(b)(3)(i)(A) and (B) are updated, the Transmission Provider shall post 
a brief, but specific, narrative explanation of the reason for the 
update. This narrative should include, if relevant, scheduling of 
planned outages and occurrence of forced transmission outages, de-
ratings of transmission facilities, scheduling of planned generation 
outages and occurrence of forced generation outages, changes in load 
forecast, changes in new facilities' in-service dates, or other events 
or assumption changes that caused the update.
    (ii) Unconstrained posted paths. (A) Postings of firm and nonfirm 
ATC, TTC, CBM, and TRM shall be posted separately by the day, showing 
for the current day and the next six days following and thereafter, by 
the month for the 12 months next following. If the Transmission 
Provider charges separately for on-peak and off-peak periods in its 
tariff, ATC, TTC, CBM, and TRM will be posted separately for the 
current day and the next six days following for each period. These 
postings are to be updated whenever the ATC changes by more than 20 
percent of the Path's TTC.
    (B) If planning and specific requested transmission studies have 
been done, seasonal capability shall be posted for the year following 
the current year and for each year following until the end of the 
planning horizon but not to exceed 10 years.
    (iii) Calculation of CBM.
    (A) The Transmission Provider must reevaluate its CBM needs at 
least quarterly.
    (B) The Transmission Provider must post its practices for 
reevaluating its CBM needs.
    (c) Posting Transmission Service Products and Prices.
    (1) * * *
    (2) Transmission Providers must provide a downloadable file of 
their complete tariffs in the same electronic format as the tariff that 
is filed with the Commission. Transmission Providers also must post all 
of their rules, standards and practices that relate to transmission 
services.
* * * * *
    (e) Posting specific transmission and ancillary service requests 
and responses--(1) General rules. (i) All requests for transmission and 
ancillary service offered by Transmission Providers under the pro forma 
tariff, including requests for discounts, and all requests to designate 
or terminate a network resource, must be made on the OASIS and posted 
prior to the Transmission Provider responding to the request, except as 
discussed in paragraphs (e)(1) (ii) and (iii) of this section. The 
Transmission Provider must post all requests for transmission service, 
for ancillary service, and for the designation or termination of a 
network resource comparably. Requests for transmission service, 
ancillary service, and to designate and terminate a network resource, 
as well as the responses to such requests, must be conducted in 
accordance with the Transmission Provider's tariff, the Federal Power 
Act, and Commission regulations.
    (ii) The requirement in paragraph (e)(1)(i) of this section, to 
post requests for transmission and ancillary service offered by 
Transmission Providers under the pro forma tariff, including requests 
for discounts, prior to the Transmission Provider responding to the 
request, does not apply to requests for next-hour service made during 
Phase I.
    (iii) In the event that a discount is being requested for ancillary 
services that are not in support of basic transmission service provided 
by the Transmission Provider, such request need not be posted on the 
OASIS.
    (iv) In processing a request for transmission or ancillary service, 
the Responsible Party shall post the same information as required in 
paragraphs (c)(4) and (d)(3) of this section, and the following 
information: the date and time when the request is made, its place in 
any queue, the status of that request, and the result (accepted, 
denied, withdrawn). In processing a request to designate or terminate 
the designation of a network resource, the Responsible Party shall post 
the date and time when the request is made.
    (v) For any request to designate or terminate a network resource, 
the Transmission Provider (at the time when the request is received), 
must post on the OASIS (and make available for download) information 
describing the request (including: name of requestor, identification of 
the resource, effective time for the designation or termination,

[[Page 32712]]

identification of whether the transaction involves the Transmission 
Provider's wholesale merchant function or any affiliate; and any other 
relevant terms and conditions) and shall keep such information posted 
on the OASIS for at least 30 days. A record of the transaction must be 
retained and kept available as part of the audit log required in Sec.  
37.7.
    (vi) The Transmission Provider shall post a list of its current 
designated network resources and all network customers' current 
designated network resources on OASIS. The list of network resources 
should include the name of the resource, its geographic and electrical 
location, its total installed capacity, and the amount of capacity to 
be designated as a network resource.
    (2) * * *
    (ii) Information to support the reason for the denial, including 
the operating status of relevant facilities, must be maintained for 
five years and provided, upon request, to the potential Transmission 
Customer.
* * * * *
    (3) Posting when a transaction is curtailed or interrupted. (ii) 
Information to support any such curtailment or interruption, including 
the operating status of the facilities involved in the constraint or 
interruption, must be maintained and made available upon request, to 
the curtailed or interrupted customer, the Commission's Staff, and any 
other person who requests it, for five years.
* * * * *
    (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 separately for requests 
for short-term firm point-to-point transmission service, long-term firm 
point-to-point transmission service, and requests to designate a new 
network resource and must be calculated and posted 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.
    (i) Process Time from Initial Service Request to Offer of System 
Impact Study Agreement.
    (A) Number of new system impact study agreements delivered during 
the reporting quarter to entities that request transmission service,
    (B) Number of new system impact study agreements delivered during 
the reporting quarter to entities that request transmission service 
more than thirty (30) days after the Responsible Party received the 
request for transmission service,
    (C) Mean time (in days), for all requests acted on by the 
Responsible Party during the reporting quarter, from the date when the 
Responsible Party received the request for transmission service to when 
the Responsible Party changed the transmission service request status 
to indicate that the Responsible Party could offer transmission service 
or needed to perform a system impact study,
    (D) Mean time (in days), for all system impact study agreements 
delivered by the Responsible Party during the reporting quarter, from 
the date when the Responsible Party received the request for 
transmission service to the date when the Responsible Party delivered a 
system impact study agreement, and
    (E) Number of new system impact study agreements executed during 
the reporting quarter.
    (ii) System Impact Study Processing Time. (A) Number of system 
impact studies completed by the Responsible Party during the reporting 
quarter,
    (B) Number of system impact studies completed by the Responsible 
Party during the reporting quarter more than 60 days after the 
Responsible Party received an executed system impact study agreement,
    (C) Mean time (in days), for all system impact studies completed by 
the Responsible Party during the reporting quarter, from the date when 
the Responsible Party received the executed system impact study 
agreement to the date when the Responsible Party provided the system 
impact study to the entity who executed the system impact study 
agreement, and
    (D) Mean cost of system impact studies completed by the Responsible 
Party during the reporting quarter.
    (iii) Transmission Service Requests Withdrawn from the System 
Impact Study Queue. (A) Number of transmission service requests 
withdrawn from the Responsible Party's system impact study queue during 
the reporting quarter,
    (B) Number of transmission service requests withdrawn from the 
Responsible Party's system impact study queue during the reporting 
quarter more than 60 days after the Responsible Party received the 
executed system impact study agreement, and
    (C) Mean time (in days), for all transmission service requests 
withdrawn from the Responsible Party's system impact study queue during 
the reporting quarter, from the date the Responsible Party received the 
executed system impact study agreement to date when request was 
withdrawn from the Responsible Party's system impact study queue.
    (iv) Process Time from Completed System Impact Study to Offer of 
Facilities Study. (A) Number of new facilities study agreements 
delivered during the reporting quarter to entities that request 
transmission service,
    (B) Number of new facilities study agreements delivered during the 
reporting quarter to entities that request transmission service more 
than thirty (30) days after the Responsible Party completed the system 
impact study,
    (C) Mean time (in days), for all facilities study agreements 
delivered by the Responsible Party during the reporting quarter, from 
the date when the Responsible Party completed the system impact study 
to the date when the Responsible Party delivered a facilities study 
agreement, and
    (D) Number of new facilities study agreements executed during the 
reporting quarter.
    (v) Facilities Study Processing Time. (A) Number of facilities 
studies completed by the Responsible Party during the reporting 
quarter,
    (B) Number of facilities studies completed by the Responsible Party 
during the reporting quarter more than 60 days after the Responsible 
Party received an executed facilities study agreement,
    (C) Mean time (in days), for all facilities studies completed by 
the Responsible Party during the reporting quarter, from the date when 
the Responsible Party received the executed facilities study agreement 
to the date when the Responsible Party provided the facilities study to 
the entity who executed the facilities study agreement,
    (D) Mean cost of facilities studies completed by the Responsible 
Party during the reporting quarter, and
    (E) Mean cost of upgrades recommended in facilities studies 
completed during the reporting quarter.
    (vi) Service Requests Withdrawn from Facilities Study Queue.

[[Page 32713]]

    (A) Number of transmission service requests withdrawn from the 
Responsible Party's facilities study queue during the reporting 
quarter,
    (B) Number of transmission service requests withdrawn from the 
Responsible Party's facilities study queue during the reporting quarter 
more than 60 days after the Responsible Party received the executed 
facilities study agreement, and
    (C) Mean time (in days), for all transmission service requests 
withdrawn from the Responsible Party's facilities study queue during 
the reporting quarter, from the date the Responsible Party received the 
executed facilities study agreement to date when request was withdrawn 
from the Responsible Party's facilities study queue
    (2) The Responsible Party is required to post the measures in 
paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section for 
each calendar quarter within 15 days of the end of the calendar 
quarter. The Responsible Party will keep the quarterly measures posted 
on OASIS for three calendar years.
    (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. The Responsible Party must calculate and post the 
measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this 
section separately for requests for short-term firm point-to-point 
transmission service, long-term firm point-to-point transmission 
service, and requests to designate a new network resource and must be 
calculated and posted separately for transmission service requests from 
Affiliates and transmission service requests from Transmission 
Customers who are not Affiliates.
    (i) Mean, across all system impact studies the Responsible Party 
completes during the reporting quarter, of the employee-hours expended 
per system impact study the Responsible Party completes during 
reporting period;
    (ii) Mean, across all facilities studies the Responsible Party 
completes during the reporting quarter, of the employee-hours expended 
per facilities study the Responsible Party completes during reporting 
period;
    (iii) The number of employees the Responsible Party has assigned to 
process system impact studies;
    (iv) The number of employees the Responsible Party has assigned to 
process facilities studies.
    (4) The Responsible Party is required to post the measures in 
paragraph (h)(3)(a) through paragraph (h)(3)(d) of this section for 
each calendar quarter within 15 days of the end of the calendar 
quarter. The Responsible Party will keep the quarterly measures posted 
on OASIS for five calendar years.
    (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 that 
have been rejected, and
    (4) The total number of Affiliate requests for transmission service 
that have been made.
    5. In Sec.  37.7, paragraph (b) is revised to read as follows:

Sec.  37.7  Auditing Transmission Service Information.

* * * * *
    (b) Audit data must remain available for download on the OASIS for 
90 days, except ATC/TTC postings that must remain available for 
download on the OASIS for 20 days. The audit data are to be retained 
and made available upon request for download for five years from the 
date when they are first posted in the same electronic form as used 
when they originally were posted on the OASIS.
---------------------------------------------------------------------------

    \450\ A ``*'' indicates that the commenter filed a notice of 
intervention only.

    Note: The following appendices will not be published in the Code 
---------------------------------------------------------------------------
of Federal Regulations.

Appendix A: Commenter Acronyms

              Initial Commenters in Docket No. RM05-25-000
------------------------------------------------------------------------
              Abbreviation                 RM05-25-000 Initial comments
------------------------------------------------------------------------
AEP....................................  American Electric Power System
                                          (AEP Texas North Company; AEP
                                          Texas Central Company;
                                          Appalachian Power Company;
                                          Columbus Southern Power
                                          Company; Indiana Michigan
                                          Power Company; Kentucky Power
                                          Company; Kingsport Power
                                          Company; Ohio Power Company;
                                          Public Service Company of
                                          Oklahoma; Southwestern
                                          Electric Power Company and
                                          Wheeling Power Company).
Alabama MEA............................  Alabama Municipal Electric
                                          Authority.
Alberta Intervenors....................  Alberta Intervenors
                                          (TransCanada Energy Ltd.;
                                          ENMAX Energy Marketing, Inc.;
                                          EPCOR Merchant and Capital,
                                          LP; and TransAlta
                                          Corporation).
Alberta System Operator................  Alberta Electric System
                                          Operator.
Alcoa..................................  Alcoa Inc. and Alcoa Power
                                          Generating Inc.
Alliance of State Leaders..............  Alliance of State Leaders
                                          Protecting Electricity
                                          Consumers.

[[Page 32714]]

Ameren.................................  Ameren Services Company
                                          (Central Illinois Light
                                          Company d/b/a AmerenCILCO;
                                          Central Illinois Public
                                          Service Company d/b/a
                                          AmerenCIPS; Illinois Power
                                          Company d/b/a AmerenIP; Union
                                          Electric Company d/b/a
                                          AmerenUE; Ameren Energy
                                          Marketing Company; Ameren
                                          Energy Generating Company; and
                                          AmerenEnergy Resources
                                          Generating Company).
American Forest and Paper* \450\.......  American Forest and Paper
                                          Association.
American Transmission..................  American Transmission Company
                                          LLC.
AMP-Ohio...............................  American Municipal Power-Ohio,
                                          Inc.
APPA...................................  American Public Power
                                          Association.
APS....................................  Arizona Public Service Company.
Arkansas Cities........................  Arkansas Cities and Cooperative
                                          (Conway Corporation; West
                                          Memphis Utilities Commission;
                                          City of Osceola, Arkansas;
                                          City of Prescott, Arkansas;
                                          Hope Water & Light Commission;
                                          and Farmers Electric
                                          Cooperative Cooperation).
Arkansas Commission....................  Arkansas Public Service
                                          Commission.
AWEA...................................  American Wind Energy
                                          Association.
BC Transmission........................  British Columbia Transmission
                                          Corporation.
Bonneville.............................  Bonneville Power
                                          Administration.
Bureau of Reclamation..................  U.S. Bureau of Reclamation.
CAISO..................................  California Independent System
                                          Operator Corporation.
California Commission..................  Public Utilities Commission of
                                          the State of California.
Calpine................................  Calpine Corporation.
Canadian Electricity Association.......  Canadian Electricity
                                          Association.
Chelan.................................  Public Utility District No. 1
                                          of Chelan County and Public
                                          Utility District No. 2 of
                                          Grant County.
Cinergy................................  Cinergy Services, Inc.
                                          (Cincinatti Gas & Electric
                                          Company; PSI Energy, Inc.; and
                                          Union Light, Heat and Power
                                          Company).
Constellation..........................  Constellation Energy Group,
                                          Inc.
Cottonwood.............................  Cottonwood Energy Company LP
                                          and Union Power Partners, LP.
Detroit Edison.........................  Detroit Edison Company.
Douglas................................  Public Utility District No. 1
                                          of Douglas County.
Duke...................................  Duke Energy Corporation.
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.
Edison Mission.........................  Edison Mission Energy, Edison
                                          Mission Marketing & Trading,
                                          Inc. and Midwest Generation
                                          EME, LLC.
EEI....................................  Edison Electric Institute.
ELCON..................................  Electricity Consumers Resource
                                          Council, American Iron and
                                          Steel Institute and American
                                          Chemistry Council.
Entergy................................  Entergy Services, Inc.
EPSA...................................  Electric Power Supply
                                          Association.
Exelon.................................  Exelon Corporation.
Fayetteville...........................  Public Works Commission of the
                                          City of Fayetteville, North
                                          Carolina.
FirstEnergy............................  FirstEnergy Service Company
                                          (FirstEnergy Solutions;
                                          American Transmission Systems,
                                          Inc.; Jersey Central Power and
                                          Light Company; Metropolitan
                                          Edison Company; and
                                          Pennsylvania Electric
                                          Company).
Florida Industrial Cogeneration          Florida Industrial Cogeneration
 Association.                             Association.
FMPA...................................  Florida Municipal Power Agency.
FP&L...................................  Florida Power & Light Company.
Hogan..................................  William H. Hogan.
HQ Energy..............................  HQ Energy Services (U.S.), Inc.
IECG*..................................  Industrial Energy Consumer
                                          Group.
Indicated New York Transmission Owners.  Indicated New York Transmission
                                          Owners (Central Hudson Gas &
                                          Electric Corp.; Consolidated
                                          Edison Company of New York,
                                          Inc.; New York State Electric
                                          & Gas Corp.; Orange and
                                          Rockland Utilities, Inc.;
                                          LIPA; New York Power
                                          Authority; and Rochester Gas
                                          and Electric Corp.).
International Transmission.............  International Transmission
                                          Company.
ISO New England........................  ISO New England, Inc. and New
                                          England Power Pool.
ISO/RTO................................  ISO/RTO Council.
KCP&L..................................  Kansas City Power & Light
                                          Company.
Kentucky Commission....................  Kentucky Public Service
                                          Commission.
Lafayette..............................  Lafayette Utilities System of
                                          the City and Parish of
                                          Lafayette, Louisiana;
                                          Mississippi Delta Energy
                                          Agency, Clarksdale Public
                                          Utilities Commission of the
                                          City of Clarksdale,
                                          Mississippi; and Public
                                          Service Commission of the City
                                          of Yazoo City, Mississippi.
LDWP...................................  City of Los Angeles Department
                                          of Water and Power.
LG&E...................................  LG&E Energy LLC (Louisville Gas
                                          and Electric Company and
                                          Kentucky Utilities Company).
LPPC...................................  Large Public Power Council.

[[Page 32715]]

MEAG...................................  MEAG Power.
Memphis Light..........................  Memphis Light, Gas & Water
                                          Division.
Metropolitan Water District............  Metropolitan Water District of
                                          Southern California.
MidAmerican............................  MidAmerican Energy Company.
Midwest Municipals.....................  Midwest Municipal Transmission
                                          Group.
Midwest SATs...........................  Midwest Stand-Alone
                                          Transmission Companies
                                          (American Transmission Company
                                          LLC; International
                                          Transmission Company; and
                                          Michigan Electric Transmission
                                          Company, LLC).
MISO...................................  Midwest Independent
                                          Transmission System Operator,
                                          Inc.
MISO States............................  Organization of MISO States.
Montana Alberta Tie....................  Montana Alberta Tie Ltd.
NARUC..................................  National Association of
                                          Regulatory Utility
                                          Commissioners.
National Grid..........................  National Grid USA.
NCPA...................................  Northern California Power
                                          Agency.
Nevada Commission......................  Public Utilities Commission of
                                          Nevada.
Nevada Companies.......................  Nevada Power Company and Sierra
                                          Pacific Power Company.
New York Commission....................  New York State Public Service
                                          Commission.
North Carolina Commission..............  North Carolina Utilities
                                          Commission; Public Staff of
                                          the North Carolina Utilities
                                          Commission; and the Attorney
                                          General of the State of North
                                          Carolina.
Northeast Utilities....................  Northeast Utilities Service
                                          Company (Connecticut Light and
                                          Power Company; Western
                                          Massachusetts Electric
                                          Company; Public Service
                                          Company of New Hampshire;
                                          Holyoke Water Power Company;
                                          and Holyoke Power and Electric
                                          Company).
Northwest IPPs.........................  Northwest Independent Power
                                          Producers Coalition (BP
                                          Energy; Calpine Corporation;
                                          EPCOR; National Energy Supply
                                          Company; Northwest Energy
                                          Development; Sempra
                                          Generation; Suez Energy North
                                          America, Inc.; and TransAlta
                                          Energy Marketing, (U.S.)
                                          Inc.).
Northwest Unregulated TUs..............  Northwest Unregulated
                                          Transmitting Utilities (Clark
                                          Public Utilities; Public
                                          Utility District No. 1 of
                                          Cowlitz County; Eugene Water
                                          and Electric Board; Public
                                          Utility District No. 2 of
                                          Grant County; Public Utility
                                          District No. 1 of Snohomish
                                          County; and Tacoma Power).
NorthWestern...........................  NorthWestern Corporation.
NPPD...................................  Nebraska Public Power District.
NRECA..................................  National Rural Electric
                                          Cooperative Association.
Occidental.............................  Occidental Chemical
                                          Corporation.
Ohio Commission........................  Public Utilities Commission of
                                          Ohio.
Oklahoma Commission....................  Oklahoma Corporation
                                          Commission.
Old Dominion...........................  Old Dominion Electric
                                          Cooperative.
PacifiCorp.............................  PacifiCorp.
PJM....................................  PJM Interconnection, L.L.C.
PNM-TNMP...............................  Public Service Company of New
                                          Mexico and Texas-New Mexico
                                          Power Company.
Portland General.......................  Portland General Electric
                                          Company.
Powerex................................  Powerex Corp.
PPL....................................  PPL Companies (PPL Electric
                                          Utilities Corporation; PPL
                                          EnergyPlus, LLC; PPL Montana,
                                          LLC; PPL Holtwood, LLC; Lower
                                          Mount Bethel Energy, LLC; PPL
                                          Maine, LLC; PPL Great Works,
                                          LLC; PPL Colstrip I, LLC; PPL
                                          Colstrip II, LLC; PPL Martins
                                          Creek, LLC; PPL Brunner
                                          Island, LLC; PPL Montour, LLC;
                                          PPL Susquehanna, LLC; PPL
                                          Wallingford Energy, LLC; PPL
                                          Southwest Generation Holdings,
                                          LLC; PPL University Park, LLC,
                                          PPL Shoreham Energy, LLC; and
                                          PPL Edgewood Energy, LLC).
Progress Energy........................  Progress Energy, Inc. (Carolina
                                          Power & Light Company d/b/a
                                          Progress Energy Carolinas and
                                          Florida Power Corporation, d/b/
                                          a Progress Energy Florida).
Public Power Council...................  Public Power Council.
Renewable Energy.......................  Renewable Energy and Public
                                          Interest Organizations
                                          (American Wind Energy
                                          Association; Citizens for
                                          Pennsylvania's Future
                                          (PennFuture); Minnesotans for
                                          an Energy Efficient Economy;
                                          Natural Resources Defense
                                          Council; Ohio Consumers'
                                          Council; Pace Energy Project;
                                          Project for Sustainable FERC
                                          Energy Policy; Renewable
                                          Northwest Project; The Stella
                                          Group, Ltd.; The Wind
                                          Coalition; and West Wind
                                          Wires).
Rural Utilities Service................  U.S. Department of Agriculture
                                          Rural Utilities Service.
Sacramento.............................  Sacramento Municipal Utility
                                          District.
Salt River.............................  Salt River Project Agricultural
                                          Improvement and Power
                                          District.
San Diego G&E..........................  San Diego Gas & Electric
                                          Company.
Santa Clara............................  City of Santa Clara, California
                                          d/b/a Silicon Valley Power.
Santee Cooper..........................  South Carolina Public Service
                                          Authority.
Sempra Global..........................  Sempra Global.
SEPA...................................  Southeastern Power
                                          Administration.

[[Page 32716]]

Snohomish..............................  Public Utility District No. 1
                                          of Snohomish County,
                                          Washington.
South Carolina E&G.....................  South Carolina Electric & Gas
                                          Company.
Southern...............................  Southern Company Services, Inc.
Southern Montana Coop..................  Southern Montana Electric
                                          Generation and Transmission
                                          Cooperative, Inc.
Southwest TDU Group....................  Southwest Transmission
                                          Dependent Utility Group
                                          (Aguila Irrigation District;
                                          Ak-Chin Energy Services;
                                          Buckeye Water Conservation and
                                          Drainage District; Central
                                          Arizona Water Conservation
                                          District; Electrical District
                                          No. 3; Electrical District No.
                                          4; Electrical District No. 5;
                                          Electrical District No. 6;
                                          Electrical District No. 7;
                                          Electrical District No. 8;
                                          Harquahala Valley Power
                                          District; Maricopa County
                                          Municipal Water District No.
                                          1; McMullen Valley Water
                                          Conservation and Drainage
                                          District; City of Needles;
                                          Roosevelt Irrigation District;
                                          City of Safford; Tonopah
                                          Irrigation District; Wellton-
                                          Mohawk Irrigation and Drainage
                                          District).
Southwestern Coop......................  Southwestern Electric
                                          Cooperative, Inc.
SPP....................................  Southwest Power Pool, Inc.
Steel Manufacturers Association........  Steel Manufacturers
                                          Association.
Suez Energy NA.........................  Suez Energy North America.
Tacoma.................................  Tacoma Power.
TANC...................................  Transmission Agency of Northern
                                          California.
TAPS...................................  Transmission Access Policy
                                          Study Group.
TDU Systems............................  Transmission Dependent
                                          Utilities Systems.
Tennessee Valley PPA...................  Tennessee Valley Public Power
                                          Association.
TransAlta..............................  TransAlta Energy Marketing
                                          (U.S.) Inc.
Trans-Elect............................  Trans-Elect, Inc.
TVA....................................  Tennessee Valley Authority.
WAPA...................................  Western Area Power
                                          Administration.
Williams...............................  Williams Power Company, Inc.
Wisconsin Commission...................  Public Service Commission of
                                          Wisconsin.
Wisconsin Electric.....................  Wisconsin Electric Power
                                          Company.
Wyoming Infrastructure*................  Wyoming Infrastructure
                                          Authority.
Xcel...................................  Xcel Energy Services, Inc.
------------------------------------------------------------------------

               Reply Commenters in Docket No. RM05-25-000
------------------------------------------------------------------------
              Abbreviation                 RM05-25-000 reply  comments
------------------------------------------------------------------------
Alberta Intervenors....................  Alberta Intervenors
                                          (TransCanada Energy Ltd.;
                                          ENMAX Energy Marketing, Inc.;
                                          EPCOR Merchant and Capital,
                                          LP; and TransAlta
                                          Corporation).
Anaheim................................  Cities of Anaheim, Azusa,
                                          Banning, Colton, Pasadena and
                                          Riverside, California.
APPA...................................  American Public Power
                                          Association.
BC Transmission........................  British Columbia Transmission
                                          Corporation.
Bonneville.............................  Bonneville Power
                                          Administration.
California Municipal Utilities           California Municipal Utilities
 Association.                             Association.
Cogeneration Association of California.  Cogeneration Association of
                                          California and Energy
                                          Producers and Users Coalition.
EEI....................................  Edison Electric Institute.
ElectriCities..........................  ElectriCities of North
                                          Carolina, Inc.
Entergy................................  Entergy Services, Inc.
EPSA...................................  Electric Power Supply
                                          Association.
Fallon.................................  City of Fallon, Nevada.
Fertilizer Institute...................  Fertilizer Institute.
FMPA...................................  Florida Municipal Power Agency.
FP&L...................................  Florida Power & Light Company.
Great Northern.........................  Great Northern Power
                                          Development, L.P.
Joint Commenters.......................  Joint Commenters (Duke Energy.
                                          Corporation, Progress Energy
                                          Corporation, South Carolina
                                          Public Service Authority and
                                          Southern Company Services,
                                          Inc.).
Lafayette\+ 451\.......................  Lafayette Utilities System of
                                          the City and Parish of
                                          Lafayette, Louisiana;
                                          Mississippi Delta Energy
                                          Agency, Clarksdale Public
                                          Utilities Commission of the
                                          City of Clarksdale,
                                          Mississippi; and Public
                                          Service Commission of the City
                                          of Yazoo City, Mississippi.
LDWP...................................  City of Los Angeles Department
                                          of Water and Power.
LPPC...................................  Large Public Power Council.
Mark Lively\+\.........................  Mark B. Lively.
MEAG...................................  MEAG Power.
Memphis Light..........................  Memphis Light, Gas & Water
                                          Division.

[[Page 32717]]

Midwest Municipals.....................  Midwest Municipal Transmission
                                          Group .
Midwest SATs...........................  Midwest Stand-Alone
                                          Transmission Companies
                                          (American Transmission Company
                                          LLC; International
                                          Transmission Company; and
                                          Michigan Electric Transmission
                                          Company, LLC).
NARUC..................................  National Association of
                                          Regulatory Utility
                                          Commissioners.
National Grid..........................  National Grid USA.
NCPA...................................  Northern California Power
                                          Agency.
Newmont Mining.........................  Newmont USA Limited, d/b/a
                                          Newmont Mining Corporation.
Northwest IPPs.........................  Northwest Independent Power
                                          Producers Coalition (BP
                                          Energy; Calpine Corporation;
                                          EPCOR; National Energy Systems
                                          Company; Northwest Energy
                                          Development; Sempra
                                          Generation; Suez Energy North
                                          America, Inc.; and TransAlta
                                          Energy Marketing, (U.S.)
                                          Inc.).
NRECA..................................  National Rural Electric
                                          Cooperative Association.
Occidental.............................  Occidental Chemical
                                          Corporation.
PacifiCorp.............................  PacifiCorp.
Powerex................................  Powerex Corp.
Progress Energy........................  Progress Energy, Inc. (Carolina
                                          Power & Light Company d/b/a
                                          Progress Energy Carolinas and
                                          Florida Power Corporation, d/b/
                                          a Progress Energy Florida).
Puget..................................  Puget Sound Energy, Inc.
Sacramento.............................  Sacramento Municipal Utility
                                          District.
Salt River.............................  Salt River Project Agricultural
                                          Improvement and Power
                                          District.
San Antonio............................  San Antonio City Public Service
                                          Board.
Seattle................................  City of Seattle--City Light
                                          Department.
South Carolina Regulatory Staff........  South Carolina Office of
                                          Regulatory Staff.
Southern...............................  Southern Company Services, Inc.
TANC...................................  Transmission Agency of Northern
                                          California.
TAPS...................................  Transmission Access Policy
                                          Study Group.
TDU Systems............................  Transmission Dependent
                                          Utilities Systems.
Truckee Donner.........................  Truckee Donner Public Utility
                                          District.
TVA....................................  Tennessee Valley Authority.
TVA Noticing Distributors\+\...........  TVA Noticing Distributors
                                          (Paducah Power Systems,
                                          Glasgow Electric Plant Board,
                                          Princeton Electric Plant Board
                                          and Hopkinsville Electric
                                          System).
Williams...............................  Williams Power Company, Inc.
------------------------------------------------------------------------

                        Commenters in RM05-17-000
------------------------------------------------------------------------
              Abbreviation                     RM05-17-000 Comments
------------------------------------------------------------------------
Allegheny..............................   Allegheny Power.
APPA...................................   American Public Power
                                          Association.
Bonneville.............................   Bonneville Power
                                          Administration.
CEOB...................................   California Electricity
                                          Oversight Board.
EEI....................................   Edison Electric Institute.
EPSA...................................   Electric Power Supply
                                          Association.
Exelon.................................   Exelon Corporation.
FTC....................................   Federal Trade Commission.
Generator Coalition....................   Generator Coalition
                                          (Cottonwood Energy Company LP;
                                          KGen Power Management Inc.;
                                          Suez Energy North America,
                                          Inc.; and Union Power
                                          Partners, LP).
International Transmission.............   International Transmission
                                          Company.
ISO/RTO................................   ISO/RTO Council.
LDWP...................................   City of Los Angeles Department
                                          of Water and Power.
MidAmerican............................   MidAmerican Energy Company.
MISO...................................   Midwest Independent
                                          Transmission System Operator,
                                          Inc.
NERC...................................   North American Electric
                                          Reliability Council.
NY Commission..........................   New York State Public Service
                                          Commission.
PG&E...................................   Pacific Gas and Electric
                                          Company.
PGP....................................   Public Generating Pool.
Powerex................................   Powerex Corp.
Southern...............................   Southern Company Services,
                                          Inc.
Southern California Edison.............   Southern California Edison
                                          Company.*
TANC...................................   Transmission Agency of
                                          Northern California.
TAPS...................................   Transmission Access Policy
                                          Study Group.
WestConnect............................   WestConnect Public Utilities.
------------------------------------------------------------------------

[[Page 32718]]

Pro Forma Open Access Transmission Tariff

Table of Contents

I. Common Service Provisions
---------------------------------------------------------------------------

    \451\ A ``+'' indicates that the commenter also filed 
supplemental comments.
---------------------------------------------------------------------------

    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 Economy Energy
    1.13 Eligible Customer
    1.14 Facilities Study
    1.15 Firm Point-To-Point Transmission Service
    1.16 Good Utility Practice
    1.17 Interruption
    1.18 Load Ratio Share
    1.19 Load Shedding
    1.20 Long-Term Firm Point-To-Point Transmission Service
    1.21 Native Load Customers
    1.22 Network Customer
    1.23 Network Integration Transmission Service
    1.24 Network Load
    1.25 Network Operating Agreement
    1.26 Network Operating Committee
    1.27 Network Resource
    1.28 Network Upgrades
    1.29 Non-Firm Point-To-Point Transmission Service
    1.30 Non-Firm Sale
    1.31 Open Access Same-Time Information System (OASIS)
    1.32 Part I
    1.33 Part II
    1.34 Part III
    1.35 Parties
    1.36 Point(s) of Delivery
    1.37 Point(s) of Receipt
    1.38 Point-To-Point Transmission Service
    1.39 Power Purchaser
    1.40 Pre-Confirmed Application
    1.41 Receiving Party
    1.42 Regional Transmission Group (RTG)
    1.43 Reserved Capacity
    1.44 Service Agreement
    1.45 Service Commencement Date
    1.46 Short-Term Firm Point-To-Point Transmission Service
    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 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
    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
    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
    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 
Point(s)

[[Page 32719]]

    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
Schedule 6
    Operating Reserve--Supplemental Reserve Service
Schedule 7
    Long-Term Firm and Short-Term Firm Point-To-Point
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 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

[[Page 32720]]

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 Economy Energy
    Energy purchased by a Network Integration Transmission customer 
that displaces that customer's own higher cost designated Network 
Resource(s) for the purpose of serving that customer's designated 
Network Load(s).
1.13 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.
1.14 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.
1.15 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.
1.16 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 
practices required by Federal Power Act section 215(a)(4).
1.17 Interruption
    A reduction in non-firm transmission service due to economic 
reasons pursuant to Section 14.7.
1.18 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 the 
Tariff and calculated on a rolling twelve month basis.
1.19 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.
1.20 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.
1.21 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.
1.22 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.
1.23 Network Integration Transmission Service
    The transmission service provided under Part III of the Tariff.
1.24 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 a 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.
1.25 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.
1.26 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

[[Page 32721]]

Transmission Service under Part III of this Tariff.
1.27 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.
1.28 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.
1.29 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.
1.30 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.
1.31 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.
1.32 Part I
    Tariff Definitions and Common Service Provisions contained in 
Sections 2 through 12.
1.33 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.
1.34 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.
1.35 Parties
    The Transmission Provider and the Transmission Customer receiving 
service under the Tariff.
1.36 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.
1.37 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.
1.38 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.
1.39 Power Purchaser
    The entity that is purchasing the capacity and energy to be 
transmitted under the Tariff.
1.40 Pre-Confirmed Application
    An Application that commits the Transmission Customer to execute a 
Service Agreement upon receipt of notification that the Transmission 
Provider can provide the requested Transmission Service.
1.41 Receiving Party
    The entity receiving the capacity and energy transmitted by the 
Transmission Provider to Point(s) of Delivery.
1.42 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.
1.43 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.
1.44 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.
1.45 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.
1.46 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.
1.47 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

[[Page 32722]]

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 
longer of a competing request by any new Eligible Customer or five 
years and to pay the current just and reasonable rate, as approved by 
the Commission, for such service. 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 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].

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 
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 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.
    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 and 6) 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 
3.6 below list the six 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 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.

[[Page 32723]]

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.

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 37 of the 
Commission's regulations (Open Access Same-Time Information System and 
Standards of Conduct for Public Utilities) and 18 CFR 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.

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 a power pool or 
Regional Transmission Group also agrees to provide comparable 
transmission service to the members of such power pool and Regional 
Transmission Group 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 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

[[Page 32724]]

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 rates, terms and conditions of service or facilities.

[[Page 32725]]

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 hour 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. However, Pre-Confirmed Applications for service will 
receive priority over earlier-submitted requests that are not Pre-
Confirmed. Within classes of requests (Pre-Confirmed or not confirmed), 
the highest price offered by the Eligible Customer is the first 
tiebreaker, followed by the date and time of the request.
    (ii) Reservations for Short-Term Firm Point-To-Point Transmission 
Service will be conditional based upon the length of the requested 
transaction. However, Pre-Confirmed Applications for Short-Term Point-
To-Point Transmission Service will receive priority over earlier-
submitted requests that are not Pre-Confirmed. Within classes of 
requests (Pre-Confirmed or not confirmed), duration is the first 
tiebreaker, followed by the highest price offered by the Eligible 
Customer, followed by the date and time of the request.
    (iii) If the Transmission System becomes oversubscribed, requests 
for longer term service may preempt requests for shorter term service 
up to the following deadlines: one hour before the commencement of 
hourly service, 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 Applications, an Eligible Customer with a reservation for shorter 
term service has the right of first refusal to match any longer term 
reservation 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. 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 August 7, 2006 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.
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 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 more 
economically by redispatching the Transmission Provider's resources 
than through constructing Network Upgrades, it shall do so, provided 
that the Eligible Customer agrees to compensate the Transmission 
Provider pursuant to the terms of Section 27. 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

[[Page 32726]]

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. 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. Transmission customers may also batch requests and 
schedules for hourly firm service to be provided on the same day. 
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 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 Pre-
Confirmed Applications and second

[[Page 32727]]

to reservations with a longer duration of service. 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 
reservation 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 August 7, 2006 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 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, or (4) transmission service for Network Customers from 
non-designated resources. 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

[[Page 32728]]

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
    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 redispatch its own 
resources or 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. To the extent a Transmission Provider cannot redispatch its own 
resources to provide the requested Firm Transmission Service, it shall 
identify generators in other control areas that could relieve the 
constraint and allow the Transmission Customer to seek redispatch with 
Transmission Providers in adjacent Control Areas.
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 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

[[Page 32729]]

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 whether the Transmission Customer 
commits to a Pre-Confirmed Request, i.e., 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. 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 transmission 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

[[Page 32730]]

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 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. 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 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 whether the Transmission Customer 
commits to a Pre-Confirmed Request, i.e., 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. 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

[[Page 32731]]

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 any system constraints and redispatch options, 
including an estimate of the number of hours of redispatch that may be 
required to accommodate the request for Transmission Service and a 
preliminary estimate of the cost of redispatch, additional Direct 
Assignment Facilities or Network Upgrades required to provide the 
requested service. 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. 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 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

[[Page 32732]]

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 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.

[[Page 32733]]

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 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 that are 
Affiliates of the Transmission Provider 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. Compensation to Resellers that are not Affiliates of 
the Transmission Provider shall be at rates established by agreement 
with 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. A Reseller should notify the Transmission Provider as soon as 
possible after any assignment or transfer of service occurs but in any 
event, notification must be provided prior to any provision of service 
to the Assignee. 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 
Parties through an amendment to the Service Agreement.

[[Page 32734]]

23.3 Information on Assignment or Transfer of Service
    In accordance with Section 4, Resellers may 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 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 more economically by redispatching the 
Transmission Provider's resources than by building new facilities or 
upgrading existing facilities 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 Economy 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

[[Continued on page 32735]]

From the Federal Register Online via GPO Access [wais.access.gpo.gov]
]                         
 
[[pp. 32735-32744]] Preventing Undue Discrimination and Preference in Transmission 
Service

[[Continued from page 32734]]

[[Page 32735]]

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.

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 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 
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), which shall include, for each Network Resource:
     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
     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;
    (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

[[Page 32736]]

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 
Customers 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 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 at any time but should 
provide notification to the Transmission Provider through OASIS as soon 
as reasonably practicable.
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. 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. The Network Customer may not 
schedule delivery of a Network Resource not physically interconnected 
with the Transmission Provider's Transmission System in excess of the 
Network Resource's capacity, as specified in the Network Customer's 
Application pursuant to Section 29. 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 Point 
of Delivery for a Network Resource not physically interconnected with 
the Transmission Provider's Transmission System exceeds the Network 
Resource's designated capacity.
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

[[Page 32737]]

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 effective date of a Final Rule in RM05-25-000], the Network 
Customer shall receive credit provided such facilities are integrated 
into the operations of the Transmission Provider's facilities and, if 
the transmission facilities were owned by the Transmission Provider, 
would be eligible for inclusion in the Transmission Provider's Annual 
Transmission Revenue Requirement. 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 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.

[[Page 32738]]

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 any system constraints and redispatch options, 
including an estimate of the number of hours of redispatch that may be 
required to accommodate the request for Transmission Service and a 
preliminary estimate of the cost of redispatch, additional Direct 
Assignment Facilities or Network Upgrades required to provide the 
requested service. 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. 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 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

[[Page 32739]]

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 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.

[[Page 32740]]

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 
North American Electric Reliability Council (NERC) and the [applicable 
regional reliability council], (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 NERC and the [applicable regional reliability 
council] requirements. 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 Sources Service

    In order to maintain transmission voltages on the Transmission 
Provider's transmission facilities within acceptable limits, generation 
facilities under the control of the control area operator are operated 
to produce (or absorb) reactive power. Thus, Reactive Supply and 
Voltage Control from Generation 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 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 limits that are generally accepted in the region and 
consistently adhered to by the Transmission Provider.
    Reactive Supply and Voltage Control from Generation 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) 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

[[Page 32741]]

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 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 only charge a Transmission Customer for either hourly 
generator imbalances under Schedule 9 or hourly energy imbalances under 
this schedule for the same imbalance, but not both.
    The Transmission Provider shall establish a deviation band of 
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). 
Parties should attempt to eliminate energy imbalances within the limits 
of the deviation band within thirty (30) days or within such other 
reasonable period of time as is generally accepted in the region and 
consistently adhered to by the Transmission Provider. If an energy 
imbalance is not corrected within thirty (30) days or a reasonable 
period of time that is generally accepted in the region and 
consistently adhered to by the Transmission Provider, the Transmission 
Customer will compensate the Transmission Provider for such service. 
Energy imbalances outside the deviation band will be subject to charges 
to be specified by the Transmission Provider. The charges for Energy 
Imbalance Service are set forth below.

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. 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. 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 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) Hourly delivery: $------/KW of Reserved Capacity per hour.
    The total demand charge in any day, pursuant to a reservation for 
Hourly delivery, shall not exceed the rate specified in section (4) 
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 (3) above times the highest amount 
in kilowatts of Reserved Capacity in any hour during such week.
    (6) 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.

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.

[[Page 32742]]

    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.

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 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 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 only charge a 
Transmission Customer for either hourly generator imbalances under this 
Schedule or hourly energy imbalances under Schedule 4 for the same 
imbalance, but not both.
    The Transmission Provider shall establish a deviation band of +/-
1.5 percent (with a minimum of 2 MW) of the scheduled transaction to be 
applied on a net hourly basis to any Generator Imbalance that occurs as 
a result of the Transmission Customer's scheduled transaction(s). The 
charges for Generator Imbalance Service are set out below:

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 (l) 
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:

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

    Transmission Customer:

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

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

[[Page 32743]]

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8.3 Direct Assignment Facilities Charge:
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8.4 Ancillary Services Charges:
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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:
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------

    Transmission Customer:
-----------------------------------------------------------------------
-----------------------------------------------------------------------
-----------------------------------------------------------------------

    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) 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 (e.g., 
load flow, short circuit, stability, transfer studies); (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, 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; and (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-time calculations).
    (c) If a Transmission Provider uses an AFC methodology to calculate 
ATC, it shall explain: (i) its definition of AFC; (ii) its AFC 
calculation methodology (e.g., load flow, short circuit, stability, 
transfer studies); (iii) its process for converting AFC into ATC; (iv) 
what databases are used in its AFC assessments; (v) the assumptions 
used in its AFC assessments; and (vi) the reliability criteria used for 
contingency outages simulation.
    (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; and (v) the process used to prevent 
double-counting of contingency outages used in its TTC and TRM 
calculations. A Transmission Provider that does not reserve 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) Who performs the assessment (transmission or merchant staff); (ii) 
the methodology used to perform generation reliability assessments 
(e.g., probabilistic or deterministic); (iii) whether the assessment 
method reflects a specific regional practice; (iv) the assumptions used 
in those assessments; 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) prove that there is no double-counting of 
contingency outages when performing CBM, TTC, and TRM calculations.
    (g) The Transmission Provider shall post its procedures for 
allowing 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 reserve CBM, it shall so state.

Attachment D--Methodology for Completing a System Impact Study

    To be filed by the Transmission Provider.

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.

[[Page 32744]]

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.

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 eight principles, as defined in the Final Rule in Docket No. 
RM05-25-000: Coordination, openness, transparency, information 
exchange, comparability, dispute resolution, regional coordination, and 
congestion studies.

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;
    (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. 06-4904 Filed 6-5-06; 8:45 am]

BILLING CODE 6717-01-P