[Federal Register Volume 62, Number 50 (Friday, March 14, 1997)]
[Rules and Regulations]
[Pages 12274-12484]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 97-5767]



[[Page 12273]]

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Part II





Department of Energy





_______________________________________________________________________



Federal Energy Regulatory Commission



_______________________________________________________________________



18 CFR Parts 35 and 37



Open Access Non-Discriminatory Transmission Services Provided by Public 
Utilities; Wholesale Competition Promotion; Stranded Costs Recovery by 
Public and Transmitting Utilities; Final Rule



Open Access Same-Time Information System and Standards of Conduct; 
Final Rule

Federal Register / Vol. 62, No. 50 / Friday, March 14, 1997 / Rules 
and Regulations

[[Page 12274]]



DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket Nos. RM95-8-001 and RM94-7-002; Order No. 888-A]


Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery of 
Stranded Costs by Public Utilities and Transmitting Utilities

Issued March 4, 1997.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule; order on rehearing.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) 
reaffirms its basic determinations in Order No. 888 and clarifies 
certain terms. Order No. 888 requires all public utilities that own, 
control or operate facilities used for transmitting electric energy in 
interstate commerce to have on file open access non-discriminatory 
transmission tariffs that contain minimum terms and conditions of non-
discriminatory service. Order No. 888 also permits public utilities and 
transmitting utilities to seek recovery of legitimate, prudent and 
verifiable stranded costs associated with providing open access and 
Federal Power Act section 211 transmission services. The Commission's 
goal is to remove impediments to competition in the wholesale bulk 
power marketplace and to bring more efficient, lower cost power to the 
Nation's electricity consumers.

EFFECTIVE DATE: This rule is effective on May 13, 1997.

FOR FURTHER INFORMATION CONTACT:

David D. Withnell (Legal Information--Docket No. RM95-8-001), Office of 
the General Counsel, Federal Energy Regulatory Commission, 888 First 
Street, N.E., Washington, D.C. 20426, (202) 208-2063
Deborah B. Leahy (Legal Information--Docket No. RM94-7-002), Office of 
the General Counsel, Federal Energy Regulatory Commission, 888 First 
Street, N.E., Washington, D.C. 20426, (202) 208-2039
Dan T. Hedberg (Technical Information--Docket No. RM95-8-001), Office 
of Electric Power Regulation, Federal Energy Regulatory Commission, 888 
First Street, N.E., Washington, D.C. 20426, (202) 208-0243
Joseph M. Power (Technical Information--Docket No. RM94-7-002), Office 
of Electric Power Regulation, Federal Energy Regulatory Commission, 888 
First Street, N.E., Washington, D.C. 20426, (202) 208-1242

SUPPLEMENTARY INFORMATION: In addition to publishing the full text of 
this document in the Federal Register, the Commission also provides all 
interested persons an opportunity to inspect or copy the contents of 
this document during normal business hours in the Public Reference Room 
at 888 First Street, N.E., Washington, D.C. 20426.
    The Commission Issuance Posting System (CIPS), an electronic 
bulletin board service, provides access to the texts of formal 
documents issued by the Commission. CIPS is available at no charge to 
the user and may be accessed using a personal computer with a modem by 
dialing 202-208-1397 if dialing locally or 1-800-856-3920 if dialing 
long distance. To access CIPS, set your communications software to 
19200, 14400, 12000, 9600, 7200, 4800, 2400, or 1200 bps, full duplex, 
no parity, 8 data bits and 1 stop bit. The full text of this order will 
be available on CIPS in ASCII and WordPerfect 5.1 format. CIPS user 
assistance is available at 202-208-2474.
    CIPS is also available through the Fed World system. Telnet 
software is required. To access CIPS via the Internet, point your 
browser to the URL address: http://www.fedworld.gov and select the ``Go 
to the FedWorld Telnet Site'' button. When your Telnet software 
connects you, log onto the FedWorld system, scroll down and select 
FedWorld by typing: 1 and at the command line then typing: /go FERC. 
FedWorld may also be accessed by Telnet at the address fedworld.gov.
    Finally, the complete text on diskette in Wordperfect format may be 
purchased from the Commission's copy contractor, La Dorn Systems 
Corporation. La Dorn Systems Corporation is also located in the Public 
Reference Room at 888 First Street, N.E., Washington, D.C. 20426.
I. Introduction and Summary
II. Public Reporting Burden
III. Background
IV. Discussion
    A. Scope of the Rule
    1. Introduction
    2. Functional Unbundling
    3. Market-based Rates
    a. Market-based Rates for New Generation
    b. Market-based Rates for Existing Generation
    4. Merger Policy
    5. Contract Reform
    6. Flow-based Contracting and Pricing
    B. Legal Authority
    C. Comparability
    1. Eligibility to Receive Non-discriminatory Open Access 
Transmission
    a. Unbundled Retail Transmission and ``Sham Wholesale 
Transactions''
    b. Transmission Providers Taking Service Under Their Tariff
    2. Service that Must be Provided by Transmission Provider
    3. Who Must Provide Non-discriminatory Open Access Transmission
    4. Reservation of Transmission Capacity by Transmission 
Customers
    5. Reservation of Transmission Capacity for Future Use by 
Utility
    6. Capacity Reassignment
    7. Information Provided to Transmission Customers
    8. Consequences of Functional Unbundling
    a. Distribution Function
    b. Retail Transmission Service
    c. Transmission Provider
    1. Taking Service Under the Tariff
    2. Accounting Treatment
    D. Ancillary Services
    1. Specific Ancillary Services
    a. Scheduling, System Control and Dispatch Service
    b. Reactive Supply and Voltage Control from Generation Sources 
Service
    c. Energy Imbalance Service
    (1) Description of Energy Imbalance
    (2) Energy Imbalance Bandwidth
    2. Ancillary Services Obligations
    a. Obligation of a Control Area Utility
    b. Obligation to Provide Dynamic Scheduling
    c. Obligation As Agent
    3. Miscellaneous Ancillary Services Issues
    a. Transmission Provider as Ancillary Services Merchant
    b. QF Receipt of Ancillary Services
    c. Pricing of Ancillary Services
    E. Real-Time Information Networks
    F. Coordination Arrangements: Power Pools, Public Utility 
Holding Companies, Bilateral Coordination Arrangements, and 
Independent System Operators . . . 179
    1. Tight Power Pools
    2. Loose Pools
    3. Public Utility Holding Companies
    4. Bilateral Coordination Arrangements
    G. Pro Forma Tariff
    1. Tariff Provisions That Affect The Pricing Mechanism
    a. Non-Price Terms and Conditions
    b. Network and Point-to-Point Customers' Uses of the System (so 
called ``Headroom'')
    c. Load Ratio Sharing Allocation Mechanism for Network Service
    (1) Multiple Control Area Network
    Customers
    (2) Twelve Monthly Coincident Peak v. Annual System Peak
    (3) Load and Generation ``Behind the Meter''
    (4) Existing Transmission Arrangements associated with 
Generating Capacity Entitlements (e.g., ``preference power'' 
customers of PMAs)
    d. Annual System Peak Pricing for Flexible Point-to-Point 
Service
    e. Opportunity Cost Pricing

[[Page 12275]]

    (1) Recovery of Opportunity Costs
    (2) Redispatch Costs
    f. Expansion Costs
    g. Credit for Customers' Transmission Facilities
    h. Ceiling Rate for Non-firm Point-to-Point Service
    i. Discounts
    j. Other Pricing Related Issues Not Specifically Addressed in 
the Final Rule
    (1) Demand Charge Credits
    (2) In-Kind Transactions
    2. Priority For Obtaining Service
    a. Reservation Priority for Existing Firm Service Customers
    b. Reservation Priority for Firm Point-to-Point and Network 
Service
    c. Reservation Priorities for Non-firm Service
    3. Curtailment and Interruption Provisions
    a. Pro-rata Curtailment Provisions
    b. Curtailment and Interruption Provisions for Non-firm Service
    4. Reciprocity Provision
    5. Liability and Indemnification
    6. Umbrella Service Agreements
    7. Other Tariff Provisions
    a. Minimum and Maximum Service Periods
    b. Amount of Designated Network Resources
    c. Eligibility Requirements
    d. Two-Year Notice of Termination Provision
    e. Termination of Service for Failure to Pay Bill
    f. Definition of Native Load Customers
    g. Off-System Sales
    h. Requirements Agreements
    i. Use of Distribution Facilities
    j. Losses
    k. Modification of Non-rate Terms and Conditions
    l. Miscellaneous Tariff Modifications
    (1) Ancillary Services
    (2) Clarification of Accounting Issues
    (a) Transmission Provider's Use of Its System (Charging 
Yourself)
    (b) Facilities and System Impact Studies
    (c) Ancillary Services
    (3) Miscellaneous Clarifications
    (a) Electronic Format
    (b) Administrative Changes
    8. Specific Tariff Provisions
    9. Miscellaneous Tariff Administrative Changes
    10. Pro Forma Tariff Compliance Filings
    H. Implementation
    1. Group 1 Public Utilities
    2. Group 2 Public Utilities
    3. Clarification Regarding Terms and Conditions Reflecting 
Regional Practices
    4. Future Filings
    5. Waiver
    I. Federal and State Jurisdiction: Transmission/Local 
Distribution
    J. Stranded Costs
    1. Justification for Allowing Recovery of Stranded Costs
    2. Cajun Electric Power Cooperative, Inc. v. FERC
    3. Responsibility for Wholesale Stranded Costs (Whether to Adopt 
Direct Assignment to Departing Customers)
    4. Recovery of Stranded Costs Associated With New Wholesale 
Requirements Contracts
    5. Recovery of Stranded Costs Associated With Existing Wholesale 
Requirements Contracts
    6. Recovery of Stranded Costs Caused by Retail-Turned-Wholesale 
Customers
    7. Recovery of Stranded Costs Caused by Retail Wheeling
    8. Evidentiary Demonstration Necessary--Reasonable Expectation 
Standard
    9. Calculation of Recoverable Stranded Costs
    10. Stranded Costs in the Context of Voluntary Restructuring
    11. Accounting Treatment for Stranded Costs
    12. Definitions, Application, and Summary
    K. Other
    1. Information Reporting Requirements for Public Utilities
    2. Small Utilities
    3. Regional Transmission Groups
    4. Pacific Northwest
    5. Power Marketing Agencies
    a. Bonneville Power Administration (BPA)
    b. Other Power Marketing Agencies
    6. Tennessee Valley Authority
    7. Hydroelectric Power
    8. Residential Customers
    9. Miscellaneous Issues
    V. Environmental Statement
    A. The Appropriate No-Action Alternative
    B. Challenges to Modeling Assumptions
    1. Appropriate Base Case
    2. Challenge to the Use of Computer Modeling
    3. Transmission Assumptions
    4. Plant Availabilities and Heat Rates
    5. Reserve Margins
    6. Northeast MOU
    7. Natural Gas Prices
    8. Expanded Transmission Analysis
    C. Mitigation
    D. Emissions Standards Disparity
    E. Short-Term Consequences of the Rule
    G. Cost Benefit Analysis
    H. Socioeconomic Impacts
    I. Coastal Zone Management Act
    VI. Regulatory Flexibility Act Certification
    A. Docket No. RM95-8-000 (Open Access Final Rule)
    1. Public Utilities
    2. Non-Public Utilities
    B. Docket No. RM94-7-000 (Stranded Cost Final Rule)
    1. Public Utilities
    2. Non-Public Utilities
    VII. Information Collection Statement
    VIII.Effective Date
    Regulatory Text
    Appendix A--List of Petitioners
    Appendix B--Pro Forma Open Access Transmission Tariff
    Statement of Commissioner Hoecker
    Statement of Commissioner Massey
    I. Introduction and Summary
    On April 24, 1996, the Commission issued Final Rules (Order Nos. 
888 and 889) intended to remedy undue discrimination in the 
provision of interstate transmission services by public utilities 
and to address the stranded costs that may result from the 
transition to more competitive electricity markets.<SUP>1 At the 
heart of these rules is a requirement that prohibits owners and 
operators of monopoly transmission facilities from denying 
transmission access, or offering only inferior access, to other 
power suppliers in order to favor the monopolists' own generation 
and increase monopoly profits--at the expense of the nation's 
electricity consumers and the economy as a whole.
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    \1\ Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities and 
Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. & 
Regs. para. 31,036, clarified, 76 FERC para. 61,009 and 76 FERC 
para. 61,347 (1996). Order No. 889 is an accompanying rule and 
specific rehearing arguments on that rule will be addressed 
separately.
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    The electric utility industry today is not the industry of ten 
years ago, or even five years ago. While historically it was assumed 
that local utilities would be the only ones to generate and transmit 
power for their customers, today there is a broad array of potential 
competitors to supply power and widespread transmission facilities that 
can carry power vast distances. But competitors cannot reach customers 
if they cannot have fair access to the transmission wires necessary to 
reach those customers. It is against this industry backdrop that the 
Commission in Order No. 888 exercised its public interest 
responsibilities pursuant to sections 205 and 206 of the Federal Power 
Act (FPA), to reexamine undue discrimination in interstate transmission 
services and the effect of that discrimination on the electricity 
customers whom we are bound to protect under the FPA.
    We here reaffirm the legal and policy bases on which Order No. 888 
is grounded. Utility practices that were acceptable in past years, if 
permitted to continue, will smother the fledgling competition in 
electricity markets and undermine the national policies reflected in 
the Energy Policy Act of 1992 to encourage the development of 
competitive markets. We firmly believe that our authorities under the 
FPA not only permit us to adapt to changing economic realities in the 
electric industry, but also require us to do so, as necessary to 
eliminate undue discrimination and protect electricity customers. The 
record supports our conclusion that, absent open access, undue 
discrimination will continue to be a fact of life in today's and 
tomorrow's electric power markets. As recent events clearly 
demonstrate, unbundled electric transmission service will be the 
centerpiece of a freely traded commodity market in electricity in which 
wholesale customers can shop for competitively-priced power.

[[Page 12276]]

    The only way to effectuate competitive markets and remedy 
discrimination is through readily available, non-discriminatory 
transmission access. The Commission estimates the potential 
quantitative benefits from such access will be approximately $3.8 to 
$5.4 billion per year in cost savings, in addition to the non-
quantifiable benefits that include better use of existing assets and 
institutions, new market mechanisms, technical innovation, and less 
rate distortion.
    Order No. 888 has two central components. The first requires all 
public utilities that own, operate or control interstate transmission 
facilities to offer network and point-to-point transmission services 
(and ancillary services) to all eligible buyers and sellers in 
wholesale bulk power markets, and to take transmission service for 
their own uses under the same rates, terms and conditions offered to 
others. In other words, it requires non-discriminatory (comparable) 
treatment for all eligible users of the monopolists' transmission 
facilities. The non-discriminatory services required by Order No. 888, 
known as open access services, are reflected in a pro forma open access 
tariff contained in the Rule. The Rule also requires functional 
separation of the utilities' transmission and power marketing functions 
(also referred to as functional unbundling) and the adoption of an 
electric transmission system information network.
    The second central component of Order No. 888 was to address 
whether and how utilities will be able to recover costs that could 
become stranded when wholesale customers use the open access tariffs, 
or FPA section 211 tariffs, <SUP>2 to leave their utilities' power 
supply systems and shop for power elsewhere. Because of competitive 
changes occurring at the retail level, as numerous states have begun 
retail transmission access programs, Order No. 888 also clarifies 
whether and when the Commission may address stranded costs caused by 
retail wheeling and the extent of the Commission's jurisdiction over 
unbundled retail transmission. The Commission further addresses the 
circumstances under which utilities and their wholesale customers may 
seek to modify contracts made under the old regulatory regime, taking 
into account the goals of reasonably accelerating customers' ability to 
benefit from competitively priced power and at the same time ensuring 
the financial stability of electric utilities during the transition to 
competition.
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    \2\ Under section 211 of the FPA, the Commission, on a case-by-
case basis upon application by an eligible customer, may order both 
public utilities and non-public utilities that own or operate 
transmission facilities used for the sale of electric energy at 
wholesale to provide transmission services to the applicant if it 
finds it is in the public interest to issue such order.
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    137 entities filed requests for rehearing and/or clarification of 
Order No. 888. While these parties raise a variety of arguments--
including legal, policy, and technical arguments--the majority 
(including a majority of public utilities) agree that we need to 
harness the benefits that competitive electricity markets can bring to 
the nation. The disagreements primarily focus on the mechanics of how 
we should do this, who should pay the costs of the transition to 
competition, and how long the transition should take.
    First, parties disagree on what is necessary to remedy undue 
discrimination and to develop truly competitive wholesale markets. Many 
focus specifically on the tariff terms and conditions of good 
transmission access and seek changes in the Order No. 888 pro forma 
tariff. In response to these types of rehearing arguments, the 
Commission has fine-tuned or changed some of the pro forma tariff terms 
and conditions to better ensure that they do not permit discrimination 
and that they result in well-functioning markets. Other petitioners 
focus on additional structural changes which they believe are 
necessary, such as mandatory corporate restructuring (divestiture of 
generation assets) or mandatory creation of independent transmission 
system operators (ISOs). With regard to restructuring, the Commission 
continues to believe that functional unbundling of the utility's 
business, not corporate divestiture or mandatory ISOs, is sufficient to 
remedy undue discrimination at this time.
    The most contentious arguments raised on rehearing involve how we 
deal with the transition costs associated with moving to competition. 
Some utilities have invested millions of dollars in facilities and 
purchased power contracts based on an explicit or implicit obligation 
to serve customers and the expectation that those customers would 
remain on their systems for the foreseeable future. These utilities 
face so-called ``stranded costs'' which, if not recovered from the 
customers that caused the costs to be incurred, could be shifted to 
other customers.
    There are two basic categories of rehearing arguments regarding 
stranded cost recovery. Most utilities want a guarantee from this 
Commission that they will recover all stranded costs, whether caused by 
losing retail customers or wholesale customers. Many customers, on the 
other hand, want to be able to abrogate existing power supply contracts 
so that they can immediately leave their current suppliers' systems and 
shop for cheaper power elsewhere, without paying the sunk costs that 
their suppliers incurred on their behalf.
    In response to these diverse arguments, the Commission has struck a 
reasonable balance that, for certain defined circumstances, permits 
utilities the opportunity to seek extra-contractual recovery of 
stranded costs from their departing customers and permits customers the 
opportunity to make a showing that their contracts should be shortened 
or terminated. Based on our experience in the natural gas area, we have 
learned that it is critical to address these issues early, but we also 
have chosen an approach different from that taken in the gas area 
because of the different circumstances facing the electric industry.
    In balancing the wide array of interests reflected in the rehearing 
petitions, we have made a number of clarifications and granted 
rehearing on some issues, but we reaffirm the core elements and 
framework of Order No. 888. Since the time the final rules issued, as 
discussed in Section III, the pace of competitive change has continued 
to escalate in the industry at both the wholesale and retail levels as 
competitors, customers and state regulatory authorities aggressively 
seek ways to lower the price of electricity. We therefore believe it is 
all the more critical that we remedy undue discrimination in interstate 
transmission services now, and that we do so generically, if we are to 
fulfill our responsibilities under the FPA to protect consumers and 
provide a fair and orderly transition to new competitive markets.
    Finally, with respect to environmental issues associated with this 
rulemaking, certain parties on rehearing continue to challenge the 
adequacy of our Final Environmental Impact Statement (FEIS). The 
central issues are whether the Final Rule will increase emissions of 
nitrogen oxides (NOx) from certain fossil-fuel fired generators, which 
could affect air quality in downwind areas to which these emissions may 
be carried, and the Commission's authority to mitigate environmental 
consequences.
    We deny rehearing on the environmental issues raised and affirm our 
conclusion that we have satisfied our obligations under NEPA. As 
discussed in detail in the Final Rule, this rulemaking is expected to 
slightly increase or slightly decrease total future

[[Page 12277]]

NOx emissions, depending on whether competitive conditions in the 
electric industry favor the utilization of natural gas or coal as a 
fuel for the generation of electricity. We also examined mitigation 
options over the longer term, and found that the preferred approach for 
mitigating any adverse environmental consequences would be for the 
Environmental Protection Agency (EPA) and the states to address the 
problem through regulatory authorities available under the Clean Air 
Act. The petitions for rehearing have not persuaded us to change this 
approach. Indeed, we note that since the issuance of Order No. 888, the 
EPA has concluded that the Rule is unlikely to have any immediate 
significant adverse environmental impact and thus concurred that the 
Commission's analysis is adequate under NEPA. We further note that EPA 
has recently taken steps under the Clean Air Act to address NOx 
emissions as part of a comprehensive emissions control program, along 
the lines endorsed by the Commission in the EIS.
    In summary, the Commission believes that our authorities under the 
FPA not only permit us to adapt to changing economic realities in the 
electric industry, but also require us to do so to eliminate undue 
discrimination and protect electricity customers. The measures required 
in Order No. 888 are necessary to remedy undue discrimination in 
interstate transmission services and provide an orderly and fair 
transition to competitive bulk power markets.
    To assist the reader, we provide below a section-by-section summary 
of key elements of this Order on Rehearing.

Scope of the Rule

    In this section we discuss petitions to rehear our requirement that 
transmission and power sales services be contracted for separately 
(unbundled). We reaffirm that this requirement is a reasonable and 
workable means of assuring non-discriminatory open access transmission. 
In doing so we refuse invitations to require that utilities under our 
jurisdiction divest themselves of generation or transmission assets. We 
do, however, make an important clarification involving how we will deal 
with existing contracts that contain so-called Mobile-Sierra clauses 
(clauses under which one or both parties agreed not to seek 
modification of contract terms unless they could show that it is 
contrary to the public interest not to permit the modification).
    In Order No. 888 we concluded that contracts would not be abrogated 
by operation of the Rule. Instead, preexisting contracts would continue 
to be honored until such time as they were revised or terminated. We 
also found that those who were operating under pre-existing 
requirements contracts containing Mobile-Sierra clauses would 
nonetheless be allowed to seek reform of the contracts on a case-by-
case basis. On rehearing we affirm that public utilities will be 
allowed to file to amend their Mobile-Sierra contracts for the limited 
purpose of providing an opportunity to seek recovery of stranded costs, 
without having to make a public interest showing that such cost 
recovery should be permitted. However, these utilities will have the 
burden, on a case-by-case basis, of showing that they had a reasonable 
expectation of continuing to serve the departing customer after the 
contract term. We clarify that if the utilities under such contracts 
seek to modify provisions that do not relate to stranded costs, they 
will have the burden of showing that the provisions are contrary to the 
public interest.
    We here make clear that, in turn, customers will be allowed to file 
to amend their Mobile-Sierra contracts to modify any contract term or 
to terminate the contract, without having to make a showing that the 
contract terms are contrary to the public interest. Instead, customers 
seeking modifications must demonstrate that the provisions they wish 
modified are no longer ``just and reasonable.'' We reaffirm our 
conclusion in the Final Rule that if a customer seeks to shorten or 
eliminate the term of its contract, however, any contract modification 
approved by the Commission will provide for appropriate stranded cost 
recovery by the customer's supplying utility.
    These various provisions meet the two-fold need to deal with 
stranded costs and the contracts under which those costs were incurred. 
However, as described in Order No. 888, the opportunity to reform 
Mobile-Sierra contracts extends only to a limited set of contracts--
those entered into on or before July 11, 1994, for requirements power.

Comparability

    In this section we deal with those requesting rehearing of our 
conclusions regarding what ``comparable'' service is, who is eligible 
for that service, and how it is to be implemented. We reaffirm our 
finding that, as a matter of law, we have jurisdiction over the rates, 
terms and conditions of unbundled transmission service provided to 
retail customers. We also clarify that we have authority to order 
``indirect'' unbundled retail transmission services and that if such 
transmission is ordered by us in the future, or if it is provided 
voluntarily, otherwise eligible customers may obtain such service under 
the open access tariff. We expect public utilities to provide such 
service in the future and, if they do not, we will not hesitate to 
order it.
    We modify in two respects the definition of who is eligible for 
open access transmission service. First, we clarify that, with respect 
to service that this Commission is prohibited from ordering by section 
212(h) of the Federal Power Act (retail wheeling directly to an 
ultimate consumer and ``sham'' wholesale wheeling), entities are 
eligible for such service under the tariff only if it is provided 
pursuant to a state requirement or is provided voluntarily. Second, we 
clarify that retail customers taking unbundled service pursuant to a 
state requirement (i.e., direct retail service) are eligible for such 
service only from those transmission providers that the state orders to 
provide service. These changes are made to make clear that our rules 
cannot be used to circumvent the proscriptions placed on the Commission 
against ordering direct retail wheeling.

Ancillary Services

    In this section we deal with petitions to rehear our definitions of 
ancillary services--those services such as scheduling, voltage control, 
and supplemental reserve service that must or can attend the providing 
of transmission service--as well as the provisions involving these 
services. We reaffirm that tariffs must separately state the charges 
for these services. We do modify some of the definitions of these 
services to conform to industry needs and practices. Most importantly, 
we make clear that the transmission provider's sale of ancillary 
services associated with providing basic transmission service is not a 
wholesale merchant function and thus does not violate the standards of 
conduct imposed with Order No. 889.

Coordination Arrangements

    The requirement to provide non-discriminatory open access 
transmission applies to any agreement between utilities that contains 
transmission rates, terms or conditions. This includes pooling 
arrangements and agreements between companies contracting to provide 
each other mutually beneficial transmission services. In Order No. 888 
we laid out rules under which the open access comparability 
requirements would apply to tight and loose power pools, public utility 
holding companies and bilateral coordination agreements.

[[Page 12278]]

We also set out principles that would govern our approval of 
independent system operator (ISO) agreements.
    In this section we affirm the rules governing coordination 
agreements. In doing so we clarify the definition of ``loose pool.'' We 
also make clear that, unlike in other situations where we require 
utilities to provide not only the services they provide themselves but 
those they could provide themselves, we will require members of loose 
pools to offer to third parties only those transmission services that 
they provide themselves under their pool-wide agreements.
    We also reaffirm our strong commitment to the concept of ISOs and 
the ISO principles described in Order No. 888. In doing so we reject 
arguments that we should require that ISOs be formed. At the same time, 
we emphasize that while there is no ``cookie-cutter'' approach to 
forming an acceptable ISO, the requirement of fair and non-
discriminatory rules of governance (Principle One) and the requirement 
that ISO employees have no financial interest in the economic interests 
of power marketers--backed by strict conflict of interest provisions--
(Principle Two) are fundamental to our approving any ISO.

Pro Forma Tariff Provisions

    The pro forma tariff is the basic mechanism implementing the 
requirements of comparable open access transmission. It provides the 
details of the transmission service obligations imposed on 
jurisdictional utilities by the Rule. On rehearing we affirm most of 
the provisions set out in Order No. 888 for the pro forma tariff. We do 
make changes to conform the pro forma tariff to changes adopted under 
other sections (for example, the definition of ``eligible customer'').
    The rehearing petitions raised many questions about how particular 
aspects of the tariff will work. For the most part, these questions 
cannot be answered generically, but must be resolved on a case-by-case 
basis in the context of specific fact situations. However, the 
petitions brought to light issues that require clarifications and in 
some cases revisions to the tariff. The most significant of these 
involve discounting practices, provisions governing priority of service 
and curtailment, and the reciprocity provision.
    Discounting practices. Originally, we provided different rules 
depending upon whether the transmission provider was offering a 
discount to itself or an affiliate or offering a discount to a non-
affiliate. In response to the rehearing petitions, we are making three 
significant changes to the discounting requirements to better permit 
the ready identification of discriminatory discounting practices while 
also providing greater discount flexibility.
    First, any discount offered on transmission services (including 
supporting ancillary services) by a transmission provider or requested 
by any customer must now be made only over the OASIS. With this change, 
all will have the same, timely access to discounted services. In making 
this change, we clarify that a transmission provider may limit its 
discounted service to particular time periods.
    Second, once the provider and customer agree on a discount, the 
details of the discounted service--the price, points of receipt and 
delivery, and length of service--must be immediately posted on the 
OASIS.
    Third, we revise our Rule respecting what other transmission paths 
must be offered at a discount. Originally, in Order No. 888, we 
required that when a discount was offered over one path, the 
transmission provider would have to provide that discount over all 
other unconstrained paths on its system. We will no longer require 
this. Instead, the discount will be limited to those unconstrained 
paths that go to the same point(s) of delivery as the discounted 
service being provided on the transmission provider's system. The 
discount will extend for the same time period and must be offered to 
all transmission service customers.
    Priority and Curtailment. We affirm the right of first refusal 
policy that reservation priority continues for firm service customers 
served under a contract of one year or more. We also affirm that 
curtailment must be made on a pro-rata basis and clarify that non-firm 
point-to-point service is subordinate to firm service. However, we 
clarify that the pro-rata curtailment requirement extends to only those 
transactions that alleviate the constraint.
    Reciprocity. In Order No. 888 we conditioned the use of a public 
utility's open access service on the agreement that, in return, it is 
offered reciprocal service by non-public utilities that own or control 
transmission facilities. Such reciprocal service does not have to be 
through an open access tariff, i.e., a tariff available to all eligible 
customers, but may be limited to those public utilities from whom the 
non-public utility obtains open access service. We affirm the 
reciprocity condition. In doing so, however, we make several 
clarifications.
    First, a public utility is free to offer transmission service to a 
non-public utility without requiring reciprocal service in return. In 
other words, it may voluntarily waive the reciprocity condition. 
However, if it chooses to do so, transmission service must be provided 
through the pro forma tariff. Alternatively, bilateral agreements for 
transmission service provided by the public utility will not be 
permitted.
    Second, we clarify that under the reciprocity condition a non-
public utility must agree to offer the Transmission Provider any 
transmission service the non-public utility provides or is capable of 
providing on its system. This means that the non-public utility 
undertaking reciprocity must have an OASIS and must operate under the 
standards of conduct imposed under Order No. 889 unless it is granted a 
waiver by the Commission or, where appropriate, by a regional 
transmission group (RTG) of which it is a member. We also clarify that 
a non-public utility cannot avoid its responsibilities by obtaining 
transmission service through other transmission customers. Further, the 
seller as well as the buyer in the chain of a transaction involving a 
non-public utility will have to comply with the reciprocity condition.
    Third, we adhere to our decision not to treat generation and 
transmission (G&T) cooperatives and their member distribution 
cooperatives as a single unit. Thus, the reciprocity provision extends 
to the G&T Cooperative and not to its member distribution cooperatives.
    Fourth, we clarify the ``safe harbor'' provision under which a non-
public utility may get a Commission decision that its transmission 
tariff suffices to meet reciprocity. A non-public utility may limit the 
use of any reciprocity tariff that it voluntarily files at the 
Commission to those transmission providers from whom the non-public 
utility obtains open access service. A non-public utility also may 
satisfy reciprocity through bilateral agreements with a public utility. 
As a related matter, if a public utility believes a non-public utility 
is violating the reciprocity condition, it may file with the Commission 
a petition to terminate its service to the non-public utility.
    Fifth, we clarify that non-public utilities may include stranded 
cost provisions in their reciprocity tariffs.
    Sixth, the order on rehearing removes the term ``interstate'' from 
the reciprocity provisions. This is to make clear that reciprocity 
applies even to those who do not own or control interstate transmission 
facilities; i.e., foreign utilities and those located in the ERCOT 
region of Texas.
    As to local furnishing bonds held by some public utilities, we 
clarify that all costs associated with the loss of tax-

[[Page 12279]]

exempt status of those bonds caused by providing open access 
transmission service are properly considered costs of providing that 
service. This includes costs of defeasing, redeeming, and refinancing 
those bonds.
    Other Clarifications. In this order on rehearing we take the 
opportunity to clarify various other tariff provisions. Among these: 
Transmission providers do not have to take service under the open 
access tariff for transmitting power purchased on behalf of their 
bundled retail customers. Also, the ability to reserve capacity to meet 
the reliability needs of a transmission provider's native load applies 
equally to present transmission and transmission that is built in the 
future.

Implementation

    On rehearing, we make no substantive changes to the implementation 
provisions originally required under Order No. 888. For the most part, 
the implementation process has been completed. Utilities have made the 
requisite tariff and compliance filings and public and non-public 
utilities have, through other orders, been provided guidance as to 
obtaining waivers of Order No. 888 and Order No. 889 requirements.
    We emphasize that we do not require the abrogation of existing 
contracts. Rather, the Rule requires only that transmission providers 
offer transmission under the open access tariff in addition to existing 
service obligations. Commitments made under existing contracts will 
continue. Of course, both transmission providers and their customers 
may seek to revise the terms and conditions of existing contracts by 
making the necessary filings, as appropriate, under Sections 205 or 206 
of the Federal Power Act.

State and Federal Jurisdiction

    On rehearing we reaffirm our decision that when transmission 
service is provided to serve retail customers apart from any contract 
for the retail sale of power, i.e., when it is provided on an unbundled 
basis, that transmission service is under our jurisdiction. In today's 
market, and increasingly in the future as more states adopt retail 
wheeling programs, retail transactions are, and will be, broken down 
into products that are sold separately--transmission and generation--
and sold by different entities. The exercise of our jurisdiction over 
the rates, terms and conditions of unbundled retail transmission will, 
therefore, become more important. We also recognize that states have 
jurisdiction over facilities used for local distribution.
    On rehearing we also reaffirm the seven-factor test of Order No. 
888 to distinguish transmission under our jurisdiction from state-
jurisdictional local distribution. In doing so, we recognize that our 
test does not resolve all possible issues. There may be other factors 
that should be taken into account. The test, therefore, is designed for 
flexibility to include unique local characteristics and usages. To that 
end, we will continue to defer to state findings on these matters.
    In addition, we clarify that states have the authority to determine 
the retail marketing areas of the electric utilities within their 
respective jurisdictions. We also recognize that states have the 
concomitant authority to determine the end user services these 
utilities provide.

Stranded Costs

    On rehearing, we reaffirm our basic decisions surrounding the 
recovery of stranded costs. Utilities will be allowed the opportunity 
to seek to recover legitimate, prudent, and verifiable wholesale 
stranded costs. This opportunity is limited to costs associated with 
serving customers under wholesale requirements contracts executed on or 
before July 11, 1994 that do not contain explicit stranded cost 
provisions; and costs associated with serving retail-turned-wholesale 
customers.

    We clarify that we will consider on a case-by-case basis whether to 
treat a contract extended or renegotiated without a stranded cost 
provision as an existing contract for stranded cost purposes.

    In each case, the opportunity to seek stranded costs is limited to 
situations in which there is a direct nexus between the availability 
and use of a Commission-required transmission tariff and the stranding 
of the costs. The Rule does not allow the recovery of costs that do not 
arise from the new, accelerated availability of non-discriminatory 
transmission access.

    The Commission also reaffirms its decision that stranded costs 
should be recovered from the customer that caused the costs to be 
incurred. The Commission is not requiring other remaining customers, or 
the utility, to shoulder a portion of its stranded costs that meet the 
requirements for recovery.

    The Commission, as described in Order No. 888, will be the primary 
forum for addressing the recovery of stranded costs caused by retail-
turned-wholesale customers. With respect to such cases, we have made 
several changes.
    First, the Commission has reconsidered its decision respecting 
cases involving existing municipal utilities that annex retail customer 
service territories. Under Order No. 888, we found that in such cases 
the Commission should not be the primary forum for determining stranded 
cost recovery. On rehearing we now find that such cases should fall 
within our province.
    Second, we clarify that the opportunity for recovery of stranded 
costs associated with retail-turned-wholesale customers applies 
regardless of whether the customer or its new supplier is the one 
requesting and contracting for the transmission service. To this end, 
we have revised the definition of ``wholesale stranded cost.''
    With respect to the recovery of stranded costs caused by unbundled 
retail wheeling, we affirm that the only circumstance in which we will 
entertain requests for these types of costs is when the state 
regulatory authority does not have authority under state law to address 
stranded costs when the retail wheeling is required. We clarify that if 
a state regulatory authority has in fact addressed such costs, 
regardless of whether it has allowed full recovery, partial recovery or 
no recovery, utilities may not apply to the Commission to recover 
stranded costs caused by the retail wheeling.

Other

    In this section we resolve questions concerning our information 
reporting requirements, regional transmission groups, and the special 
situations posed by utilities in the Pacific Northwest and by federal 
power marketing and similar agencies. Here we make some minor 
clarifications but make no significant changes to Order No. 888.
    We are not persuaded that the information reporting requirements 
need to be changed at this time. Finally, we reject arguments that 
would have us fix generically any particular rate methodology for 
providing open access transmission service under the pro forma tariff.

II. Public Reporting Burden

    This order on rehearing issues a number of minor revisions to the 
Final Rule. We find, after reviewing these revisions, that they do not, 
on balance, increase the public reporting burden.
    The Final Rule contained an estimated annual public reporting 
burden based on the requirements of the Open Access Final Rule and the 
Stranded Cost Final Rule.<SUP>3 Using the

[[Page 12280]]

burden estimate contained in the Final Rule as a starting point, we 
evaluated the public burden estimate contained in the Final Rule in 
light of the revisions contained in this order and assessed whether 
this estimate needed revision. We have concluded, given the minor 
nature of the revisions, and their offsetting nature, that our estimate 
of the public reporting burden of this order on rehearing remains 
unchanged from our estimate of the public reporting burden contained in 
the Final Rule. The Commission has conducted an internal review of this 
conclusion and has assured itself that there is specific, objective 
support for this information burden estimate. Moreover, the Commission 
has reviewed the collection of information required by the Final Rule, 
as revised by this order on rehearing, and has determined that the 
collection of information is necessary and conforms to the Commission's 
plan, as described in the Final Rule, for the collection, efficient 
management, and use of the required information.
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    \3\ 61 FR 21540 at 21543; FERC Stats. & Regs. para. 31,036 at 
31,638 (1996). No comments were filed in objection to the public 
burden estimate contained in the Open Access Final Rule and the 
Stranded Cost Final Rule.
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    Persons wishing to comment on the collections of information 
required by the Final Rule, as modified by this order on rehearing, 
should direct their comments to the Desk Officer for FERC, Office of 
Management and Budget, Room 3019 NEOB, Washington, D.C. 20503, phone 
202-395-3087, facsimile: 202-395-7285 or via the Internet at 
<a href="/cdn-cgi/l/email-protection#4e26272222272b3c11113a0e2f7f602b213e60292138"><span class="__cf_email__" data-cfemail="3a52535656535f4865654e7a5b0b145f554a145d554c">[email protected]</span></a>. Comments must be filed with the Office of 
Management and Budget within 30 days of publication of this document in 
the Federal Register. Three copies of any comments filed with the 
Office of Management and Budget also should be sent to the following 
address: Ms. Lois Cashell, Secretary, Federal Energy Regulatory 
Commission, Room 1A, 888 First Street, N.E., Washington, D.C. 20426. 
For further information, contact Michael Miller, 202-208-1415.

III. Background

    In the Final Rule, we detailed the events that led up to this 
rulemaking, including the significant technical, statutory and 
regulatory changes that have occurred in the electric industry since 
the FPA was enacted in 1935.<SUP>4 In particular, we focused on the 
competitive influences of the Public Utility Regulatory Policies Act of 
1978, the Congressional mandate in the Energy Policy Act of 1992 to 
encourage competition in electricity markets, and the need for reform 
in the industry if consumers are to achieve the benefits that greater 
competition can bring.
---------------------------------------------------------------------------

    \4\ FERC Stats. & Regs. at 31,638-52; mimeo at 13-51.
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    In the ten months since the Final Rule issued, competitive changes 
have escalated at an even faster pace in virtually all areas of the 
electric industry. These changes are driven not only by the 
Commission's Final Rule, but also by state restructuring initiatives 
and by continuing pressures from customers to take advantage of 
emerging competitive markets and the lower electricity rates they can 
bring.
    All of the existing 166 public utilities that own, control or 
operate interstate transmission facilities (listed as Group 1 and Group 
2 utilities in the Final Rule) have filed the Order No. 888 pro forma 
open access tariff or requested a waiver of the requirement. Similarly, 
they either have adopted an electronic information network or requested 
a waiver of the requirement. Five non-public utilities have submitted 
reciprocal transmission tariffs and more than 20 have requested a 
waiver of the reciprocity condition in the pro forma tariff.<SUP>5
---------------------------------------------------------------------------

    \5\ As a condition of using a public utility's open access 
tariff, any user, including non-public utilities, must offer 
reciprocal comparable transmission access to the public utility in 
return. Order No. 888 provides a voluntary mechanism whereby non-
public utilities can obtain Commission confirmation that what they 
are offering meets the tariff reciprocity condition. Non-public 
utilities also may seek a waiver of the reciprocity condition.
---------------------------------------------------------------------------

    Significant competitive changes also have accelerated with respect 
to power pooling, state restructuring initiatives, and Independent 
System Operators (ISOs). Under Order No. 888 and subsequent 
implementation orders, the Commission required the filing of revised 
pooling agreements and joint pool-wide transmission tariffs by December 
31, 1996, in order to remedy undue discrimination in transmission 
services provided through interstate power pooling arrangements. Among 
the power pool filings were a New England (NEPOOL) comprehensive 
restructuring proposal, a New York proposal, a Pennsylvania-New Jersey-
Maryland (PJM) compliance filing and a Western Systems Power Pool 
filing.
    In response to the Commission's encouragement in Order No. 888 of 
ISOs as a possible means for accomplishing comparable access, a number 
of utilities and states are well underway in developing this new 
institution. The fundamental purpose of an ISO is to operate the 
transmission systems of public utilities in a manner that is 
independent of any business interest in sales or purchases of electric 
power by those utilities. The Commission has received several proposals 
for forming ISOs, one as part of the multi-docketed filing engendered 
by California's restructuring plan, and others relating to power pool 
filings. A number of regions are also developing ISO proposals. Some 
regions previously considering regional transmission groups (RTGs), 
whose primary purpose is regional planning of transmission facility 
construction and upgrades, have now broadened their discussions to 
include an ISO.
    Investor-owned utilities in California, at the order of both the 
state commission and the legislature, have filed proposals with the 
Commission that would transfer control of transmission facilities to an 
ISO in conjunction with the formation of a state-wide power exchange to 
facilitate both wholesale and retail access. While the case presents 
many complex issues for the Commission to resolve, the California 
proposal is fundamentally compatible with the pro-competitive open-
access requirements of Order Nos. 888 and 889. The Commission's open-
access policies therefore have provided a framework for California, and 
other states, to explore customer choice initiatives.
    Other major regions of the country also are instituting ISOs. 
Member utilities of the PJM Power Pool filed competing ISO proposals 
with the Commission and are currently working to reconcile the 
differences between their proposals. The New York Power Pool recently 
filed a proposal to create an ISO and a power exchange for New York. 
The New England Power Pool is exploring a new industry structure for 
its region that centers on the creation of an ISO. Utilities and other 
market participants in the Electric Reliability Council of Texas have 
also formed an ISO. Discussions are underway among utilities from 
Virginia to Wisconsin in an attempt to create a Midwestern ISO. Members 
of the Mid-America Power Pool are discussing an ISO proposal. In the 
Pacific Northwest, utilities are involved in negotiations intended to 
lead to the formation of an independent grid operator (Indego).
    The combined available generation resources of the utilities in 
these groups is on the order of 428 GW out of a total of approximately 
732 GW for total U.S. resources (as of the end of 1996). Thus, assuming 
these ISO arrangements come to fruition, about three-fifths of the 
industry may have independent system operators controlling their 
transmission systems.
    Moreover, every state but one has proposed or is considering or 
developing retail competition programs. For example, New Hampshire, 
Illinois

[[Page 12281]]

and Massachusetts began pilot programs in the past year, and retail 
transmission service for these pilot programs currently is being taken 
pursuant to tariffs approved by both the state commissions and this 
Commission. The Massachusetts Department of Public Utilities has sent a 
proposal to the state legislature calling for retail competition to 
begin in January 1998. The New York Public Service Commission has 
issued an order proposing that retail competition begin in early 1998. 
The New Jersey Board of Public Utilities has issued a proposal 
permitting customer choice beginning in October of 1998. The Vermont 
Public Service Board has sent a plan to the legislature recommending 
that full customer choice begin by the end of 1998. The Arizona 
Corporation Commission has adopted rules to phase in competition over 
four years, beginning in January 1999. Recently, the Maine Public 
Utilities Commission issued a final report and recommendation to the 
legislature for retail competition to begin in January 2000. In 
addition, Rhode Island and Pennsylvania both have new laws requiring 
customer choice. These are only a few of the many state initiatives 
that are under way that will dramatically alter the structure of the 
electric industry.
    Since Order No. 888 was issued, significant efforts also have been 
made to ensure that reliability of the transmission grid is maintained 
and that reliability criteria are compatible with competitive markets. 
The North American Electric Reliability Council (NERC) has continued 
its efforts to broaden its membership and to fashion reliability 
requirements to fit a more competitive electric power industry. For 
example, the NERC Board of Directors voted to require mandatory 
compliance by all power market participants with its reliability 
standards. NERC is also establishing new entities called regional 
security coordinators to oversee the stability of grid operations and 
to direct the development of an extensive new communications network. 
Various NERC committees are considering ways to improve the tracking of 
power transactions, identify the network impacts of transactions, and 
reflect the actual flow of power over the network when making 
reservations for transmission service. These efforts are likely to 
intensify as the industry continues to adapt to competitive changes 
occurring in the marketplace.
    Thus, all segments of the electric industry have taken significant 
steps in the past year in response to the emerging wholesale 
competitive markets enabled by Order No. 888 as well as state retail 
competition initiatives. The competitive framework established by Order 
No. 888, whose centerpiece is non-discriminatory transmission services 
and a fair and orderly stranded cost recovery mechanism, is critical to 
the successful transition to, and full development of, the industry 
restructuring proposals that are well underway in all major regions of 
the country.

IV. Discussion

A. Scope of the Rule

1. Introduction

Rehearing Requests

Severability of Rules

    Several entities assert that the Commission should find that the 
requirements of open access transmission and stranded cost recovery are 
not severable.<SUP>6 They argue that if one of these provisions is 
invalidated by a court or otherwise removed, the orders in their 
entirety should be withdrawn or stayed pending reconsideration by the 
Commission, and public utilities should be allowed to withdraw or file 
amended transmission tariffs.
---------------------------------------------------------------------------

    \6\ E.g., Nuclear Energy Institute, Southern, EEI. EEI and 
Nuclear Energy Institute also argue that Order No. 889 should not be 
severable.
---------------------------------------------------------------------------

Commission Conclusion

    The Commission will not, at this time, make any determination 
whether or not the open access transmission, stranded cost recovery and 
OASIS provisions of Order Nos. 888 and 889 are severable. Accordingly, 
we make no finding whether, if one of these provisions is invalidated, 
Order Nos. 888 and 889 should be withdrawn or stayed in their entirety. 
We believe that our decisions in Order Nos. 888 and 889 will be upheld 
by the courts. Moreover, it would be premature to consider the 
appropriateness of a stay or withdrawal at this time. Circumstances at 
the time of any court order would dictate how we should proceed and we 
would consider all such circumstances, and the entirety of our policy 
decisions, before determining how to respond to a court decision.
2. Functional Unbundling
    In the Final Rule, the Commission found that functional unbundling 
of wholesale generation and transmission services is necessary to 
implement non-discriminatory open access transmission.<SUP>7 At the 
same time, the Commission recognized that additional safeguards were 
necessary to protect against market power abuses. Thus, the Commission 
adopted a code of conduct, discussed in detail in the final rule on 
OASIS, to ensure that the transmission owner's wholesale power 
marketing personnel and the transmission customer's power marketing 
personnel have comparable access to information about the transmission 
system. The Commission also noted that section 206 of the FPA is 
available if a public utility seeks to circumvent the functional 
unbundling requirements.
---------------------------------------------------------------------------

    \7\ FERC Stats. & Regs. at 31,654-56; mimeo at 57-61.
---------------------------------------------------------------------------

    As a further precaution against unduly discriminatory behavior, the 
Commission stated that it will continue to monitor electricity markets 
to ensure that functional unbundling adequately protects transmission 
customers. The Commission also indicated that it would continue to 
observe both the evolution of competitive power markets and the 
progress of the industry in adapting structurally to competitive 
markets. If it subsequently becomes apparent that functional unbundling 
is inadequate or unworkable in assuring non-discriminatory open access 
transmission, the Commission indicated that it would reevaluate its 
position and decide whether other mechanisms, such as ISOs, should be 
required.
    The Commission concluded that functional unbundling, coupled with 
these safeguards, is a reasonable and workable means of assuring that 
non-discriminatory open access transmission occurs. In the absence of 
evidence that functional unbundling will not work, the Commission 
indicated that it was not prepared to adopt a more intrusive and 
potentially more costly mechanism--corporate unbundling--at this time.

Rehearing Requests

    Several entities disagree with the Commission's decision to require 
functional unbundling of wholesale generation and transmission as a 
means of assuring non-discriminatory open access transmission.<SUP>8 
American Forest & Paper argues that utilities must be required to 
divest or spin-off their generating assets through operational 
unbundling or divestiture. It alleges that it was arbitrary and 
capricious, and not supported by evidence, for the Commission to rely 
on a monopolist's code of conduct to protect against monopoly abuses. 
Nucor asserts that a financial conflict of interest remains and that 
the Commission cannot monitor the exchanges of information between 
utility generation and transmission employees. It declares that a 
credible

[[Page 12282]]

information disclosure requirement is needed that makes generation cost 
and production data visible to all participants on a same-time basis. 
NY Municipal Utilities also believes that the Commission did not go far 
enough and argues that the Commission should have required operational 
unbundling, at least for tight power pools.
---------------------------------------------------------------------------

    \8\ E.g., American Forest & Paper, Nucor, NY Municipal 
Utilities.
---------------------------------------------------------------------------

Commission Conclusion

    The Commission reaffirms its finding in the Final Rule that, based 
on the information available at this time, functional unbundling, along 
with the flexible safeguards discussed in the Final Rule, is a 
reasonable and workable means of assuring non-discriminatory open 
access transmission. We see no need to adopt a more intrusive and 
potentially more costly approach at this time based on speculative 
allegations that functional unbundling may not work and that more 
severe measures may be needed. Indeed, despite a number of 
opportunities to do so, no entity has submitted any evidence suggesting 
that this less intrusive approach would not work. We do emphasize, 
however, that we have not adopted a rigid approach, but have indicated 
a willingness to monitor the situation and, if events require, 
reevaluate our decision and decide whether another mechanism may be 
more appropriate. Until we see evidence that functional unbundling will 
not work, we will continue to require functional unbundling, with the 
safeguards enumerated in the Final Rule and in Order No. 889.
3. Market-Based Rates
a. Market-Based Rates for New Generation
    In the Final Rule, the Commission codified its determination in 
Kansas City Power & Light Company (KCP&L) <SUP>9 that the generation 
dominance standard for market-based sales from new capacity should be 
dropped.<SUP>10 The Commission explained that it had yet to find an 
instance of generation dominance in long-run bulk power markets and no 
commenter had presented any evidence to that effect. However, the 
Commission emphasized that it will not ignore specific evidence 
presented by an intervenor that a seller requesting market-based rates 
for sales from new generation nevertheless possesses generation 
dominance.
---------------------------------------------------------------------------

    \9\ 67 FERC para. 61,183 at 61,557 (1994).
    \10\ FERC Stats. & Regs. at 31,656-57; mimeo at 63-66.
---------------------------------------------------------------------------

    The Commission further clarified that dropping the generation 
dominance standard for new capacity does not affect the demonstration 
that an applicant must make in order to qualify for market-based rates 
for sales from its existing generating capacity.

Rehearing Requests

    Several entities take issue with the Commission's determination to 
drop the generation dominance standard for market-based sales from new 
capacity.<SUP>11 American Forest & Paper argues that the Commission 
should delay its decision until effective competition has been 
demonstrated to exist in all markets. SC Public Service Authority 
maintains that the Commission must determine on a case-by-case basis 
whether public utilities have market power (for both existing and new 
capacity). It further argues that the Commission must develop an 
analysis of structural conditions to use in assessing the potential for 
market power consistent with that used by DOJ and FTC in merger 
proceedings and that reflects the conditions of the industry. SC Public 
Service Authority also asserts that the Commission must require as a 
condition of market rates for sales in the bulk power market, which it 
defines to be limited to sales to integrated utilities, that the 
selling utility file rate cases with the Commission and the applicable 
state commissions to avoid subsidization by captive consumers.
---------------------------------------------------------------------------

    \11\ E.g., American Forest & Paper, SC Public Service Authority, 
TDU Systems, LEPA, San Francisco.
---------------------------------------------------------------------------

    TDU Systems alleges that the long-run bulk power market upon which 
the KCP&L decision was based is overly broad and ignores the 
distinction between firm power, which ``entities subject to others' 
market power are most commonly in need of'' and other bulk power 
services. TDU Systems take issue with the Commission's conclusion in 
KCP&L that large numbers of capacity offers from IPPs and QFs 
demonstrate that the market abounds with competitors. TDU Systems 
argues that the Commission's ``assumption that large numbers of offers 
of power equate with large numbers of offers of firm power is 
questionable at best, and very likely incorrect.'' <SUP>12 Similarly, 
LEPA argues that the Commission ignored evidence submitted by LEPA in 
comments ``that the transmission dominant utility still retained 
monopoly power over RQ [requirements] markets on which LEPA's members 
are dependent for their bulk power supply.'' Because the Commission 
ignored the RQ market and the evidence of concentration in that market, 
LEPA asserts that the Commission's decision is reversible error. LEPA 
further argues that the Commission ignored the undisputed testimony of 
LEPA's witness that reliability requirements constrain the geographic 
scope of the RQ market severely.
---------------------------------------------------------------------------

    \12\ TDU Systems at 92.
---------------------------------------------------------------------------

    San Francisco argues that the burden to demonstrate affirmatively 
the absence of capacity constraints as a precondition to receiving 
authority to charge market-based rates for sales from new capacity 
should be upon public utility applicants, who possess the information 
concerning capacity constraints.

Commission Conclusion

    We reaffirm our decision to codify the determination in KCP&L that 
the generation dominance standard for market-based sales from new 
capacity should be dropped. Petitioners have not presented any evidence 
that demonstrates generation dominance in long-run bulk power markets 
and, as discussed in Order No. 888, we have found no such evidence of 
generation dominance in any of the numerous market-based rate cases 
decided by the Commission since KCP&L. In addition, as described in 
Order No. 888, the Commission will consider evidence of generation 
dominance, including generation dominance that results from 
transmission constraints, when such evidence is presented by an 
intervenor in a market-based rate case in which a utility seeks market-
based pricing associated with new capacity.
    American Forest & Paper's argument that the Commission should delay 
codification of KCP&L until effective competition has been demonstrated 
to exist in all markets ignores the fact that we have eliminated the 
generation dominance standard for market-based rates from new capacity 
only, and that the generation standard still applies to applications 
for market-based rates from existing generation. Other entities 
similarly argue that other markets in which utilities may sell power 
from new capacity may be highly concentrated with respect to 
generation, or that these utilities may otherwise be able to exert 
market power. Specifically, TDU Systems and LEPA express concern that 
the new policy may result in the exercise of market power over very 
specific bulk power products.
    To allay these concerns, we note that eliminating the generation 
dominance showing applies only to sales from new capacity. It does not 
apply to entire classes of service or to specific products. In 
addition, the policy eliminates the showing only as a matter of routine 
in each filing. We reemphasize that the Commission will consider 
specific evidence of generation dominance

[[Page 12283]]

associated with new capacity at the time the seller seeks market-based 
rates for the new capacity, including whether the addition of the new 
capacity, when combined with existing capacity, results in generation 
dominance. This clearly includes situations where existing sources of 
generation must be combined with new resources to produce a firm power 
supply. Where entry barriers are a concern, intervenors are free to 
raise the issue.
    SC Public Service Authority also raises a number of concerns 
relating to the ability of utilities to exercise market power if they 
are permitted to sell new capacity at market-based rates. These 
concerns generally include how the Commission determines product and 
geographic markets, and the standards used to determine whether sellers 
can exercise market power. In response to these concerns, as noted 
above public utility owners of new capacity must still seek case-by-
case approval before they can sell power from new capacity at market-
based rates and, as stated in the Final Rule, intervenors may present 
specific evidence that a seller requesting such market rates possesses 
generation dominance or otherwise has market power.<SUP>13 These 
requirements include considerations of transmission market power, 
whether other barriers to entry exist and whether there is evidence of 
affiliate abuse or reciprocal dealing.
---------------------------------------------------------------------------

    \13\ We do not agree with entities that claim that our decision 
to rely on evidence raised by intervenors in particular cases with 
respect to transmission constraints improperly shifts the burden 
away from the utility, which has the greatest access to information 
concerning those constraints. Given that we have yet to see any 
evidence of generation dominance in long-term bulk power markets we 
do not believe that it is appropriate to burden all market-based 
rate applicants with significant information requirements as an 
initial matter. However, if an intervenor raises a specific factual 
concern with respect to a transmission constraint that may result in 
the exercise of market power in a particular case, we will examine 
those facts in a paper or formal hearing. In that context, the 
utility would be required to come forward with information 
sufficient to permit a full examination of the effect of the 
constraint on the applicant's ability to exercise market power.
---------------------------------------------------------------------------

b. Market-based Rates for Existing Generation
    In the Final Rule, the Commission found that there is not enough 
evidence on the record to make a generic determination about whether 
market power may exist for sales from existing generation.<SUP>14 The 
Commission indicated that it would continue its case-by-case approach 
that allows market-based rates based on an analysis of generation 
market power in first tier and second tier markets.<SUP>15 The 
Commission further indicated that while it will continue to apply the 
first-tier/second-tier analysis, it will allow applicants and 
intervenors to challenge the presumption implicit in the Commission's 
practice that the relevant geographic market is bounded by the second-
tier utilities. Finally, the Commission stated that it would maintain 
its current practice of allowing market-based rates for existing 
generation to go into effect not subject to refund.<SUP>16 To the 
extent that either the applicant or an intervenor in individual cases 
offers specific evidence that the relevant geographic market ought to 
be defined differently than under the existing test, the Commission 
indicated that it will examine such arguments through formal or paper 
hearings.
---------------------------------------------------------------------------

    \14\ FERC Stats. & Regs. at 31,660; mimeo at 73-75.
    \15\ See, e.g., Southwestern Public Service Company, 72 FERC 
para. 61,208 at 61,996 (1995), reh'g pending.
    \16\ The Final Rule contained a typographical error in which the 
word ``not'' was erroneously omitted.
---------------------------------------------------------------------------

Rehearing Requests

    No rehearing requests were filed with respect to this matter.
4. Merger Policy
    In the Final Rule, the Commission explained that it had issued a 
Notice of Inquiry (NOI) on the Commission's merger policy in Docket No. 
RM96-6-000.<SUP>17 The Commission indicated that it will review whether 
its criteria and policies for evaluating mergers need to be modified in 
light of the changing circumstances, including the Final Rule, that are 
occurring in the electric industry. The Commission concluded that it 
would review its merger policy in the ongoing NOI proceeding.<SUP>18
---------------------------------------------------------------------------

    \17\ FERC Stats. & Regs. para. 35,531 (1996).
    \18\ FERC Stats. & Regs. at 31,661; mimeo at 77-78.
---------------------------------------------------------------------------

Rehearing Requests

    No rehearing requests were filed with respect to this matter.

Commission Conclusion

    We note that on December 18, 1996, the Commission issued, in the 
NOI proceeding, a Policy Statement that updates and clarifies the 
Commission's procedures, criteria and policies concerning public 
utility mergers.<SUP>19
---------------------------------------------------------------------------

    \19\ Order No. 592, Policy Statement Establishing Factors the 
Commission will Consider in Evaluating Whether a Proposed Merger is 
Consistent with the Public Interest, 77 FERC para. 61,263 (1996).
---------------------------------------------------------------------------

5. Contract Reform

Requirements and Transmission Contracts

    In the Final Rule, the Commission concluded that it was not 
appropriate to order generic abrogation of existing requirements and 
transmission contracts, but concluded nonetheless that the modification 
of certain requirements contracts (those executed on or before July 11, 
1994) on a case-by-case basis may be appropriate.<SUP>20 The Commission 
further concluded that, even if customers under such requirements 
contracts are bound by so-called Mobile-Sierra clauses, they ought to 
have the opportunity to demonstrate that their contracts no longer are 
just and reasonable.
---------------------------------------------------------------------------

    \20\ FERC Stats. & Regs. at 31,663-66; mimeo at 84-92.
---------------------------------------------------------------------------

    The Commission found that it would be against the public interest 
to permit a Mobile-Sierra clause in an existing wholesale requirements 
contract <SUP>21 to preclude the parties to such a contract from the 
opportunity to realize the benefits of the competitive wholesale power 
markets. Thus, it explained, a party to a requirements contract 
containing a Mobile-Sierra clause no longer will have the burden of 
establishing independently that it is in the public interest to permit 
the modification of such contract. The party, however, still will have 
the burden of establishing that such contract no longer is just and 
reasonable and therefore ought to be modified.
---------------------------------------------------------------------------

    \21\ The Commission defined these as contracts executed on or 
before July 11, 1994.
---------------------------------------------------------------------------

    The Commission explained that this finding complements the 
Commission's finding that, notwithstanding a Mobile-Sierra clause in an 
existing requirements contract, it is in the public interest to permit 
amendments to add stranded cost provisions to such contracts if the 
public utility proposing the amendment can meet the evidentiary 
requirements of the Final Rule. Accordingly, the Commission required 
that any contract modification approved under this Section must provide 
for the utility's recovery of any costs stranded consistent with the 
contract modification. Further, the Commission concluded that if a 
customer is permitted to argue for modification of existing contracts 
that are less favorable to it than other generation alternatives, then 
the utility should be able to seek modification of contracts that may 
be beneficial to the customer.

Coordination Agreements

    The Commission concluded that to assure that non-discriminatory 
open access becomes a reality in the relatively near future, it was 
necessary to modify existing economy energy coordination agreements. 
The Commission stated that it would condition future sales and

[[Page 12284]]

purchase transactions under existing economy energy coordination 
agreements <SUP>22 to require that the transmission service associated 
with those transactions be provided pursuant to the Final Rule's 
requirements of non-discriminatory open access, no later than December 
31, 1996. The Commission also required that, for new economy energy 
coordination agreements <SUP>23 where the transmission owner uses its 
transmission system to make economy energy sales or purchases, the 
transmission owner must take such service under its own transmission 
tariff as of the date trading begins under the agreement.<SUP>24
---------------------------------------------------------------------------

    \22\ The Commission defined ``existing'' as those agreements 
executed prior to 60 days after publication of the Final Rule in the 
Federal Register.
    \23\ The Commission defined ``new'' as those agreements executed 
60 days after publication of the Final Rule in the Federal Register.
    \24\ Accordingly, the Commission explained, transmission service 
needed for sales or purchases under all new economy energy 
coordination agreements will be pursuant to the Final Rule pro forma 
tariff.
---------------------------------------------------------------------------

    Finally, the Commission concluded that it would not require the 
modification of non-economy energy coordination agreements. However, 
the Commission noted that this does not insulate such agreements from 
complaints that transmission service provided under such agreements 
should be provided pursuant to the Final Rule pro forma tariff.

Rehearing Requests

    Various utilities oppose the Commission's finding that it is in the 
public interest to permit the modification of existing requirements 
contracts that contain Mobile-Sierra clauses. On the other hand, a 
number of customers assert that the Commission did not go far enough 
and seek enhanced contract reformation rights.

Utilities Against Contract Reformation

    Several utilities argue that the Commission's finding is not 
supported by substantial evidence.<SUP>25 Utilities For Improved 
Transition asserts that the Commission cannot rely on economic theory 
as a substitute for substantial evidence.<SUP>26 It argues that the 
record in this proceeding demonstrates that the marketplace is becoming 
increasingly competitive without mandatory tariffs, which is evidence 
of market health, not market problems. It further argues that even if 
undue discrimination is proven, the remedy is not needed because the 
record shows that existing programs are meeting the industry's needs.
---------------------------------------------------------------------------

    \25\ Utilities For Improved Transition, Union Electric, PSE&G, 
Carolina P&L.
    \26\ Union Electric adds that there is no evidence that any 
existing economy energy coordination agreements are unduly 
discriminatory and require modification.
---------------------------------------------------------------------------

    Southwestern argues that the Commission has improperly chosen to 
ignore the public interest standard and has failed to make the contract 
specific analysis here that it performed in Northeast Utils. Serv. Co., 
66 FERC para. 61,332 (1994), aff'd, 55 F.3d 686 (1st Cir. 1995). PSE&G 
and Carolina P&L also argue that the Commission failed to demonstrate 
the ``unequivocal public necessity'' for generically abrogating the 
Mobile-Sierra clauses and assert that the Commission has presented no 
evidence as to how the public interest will be served by abrogating 
these contracts. PSE&G and Carolina P&L further argue that the 
Commission cannot avoid making a public interest determination ``by the 
simple expedient of asserting that the public interest requires it to 
ignore the Mobile-Sierra clauses that required that public-interest 
determination in the first place.'' <SUP>27
---------------------------------------------------------------------------

    \27\ PSE&G at 6.
---------------------------------------------------------------------------

    Union Electric and PSE&G argue that the Commission, in justifying 
its public interest finding, inappropriately focused on the interests 
of the parties to the contract instead of on whether non-parties will 
be adversely affected by the existing contracts.
    Public Service Co of CO asserts that the Commission should clarify 
the definition of requirements contract to include long-term block 
purchases of electricity. It states that it purchases a large 
percentage of its system requirements under long-term block purchase 
agreements, and that under the Commission's abrogation policy in Order 
No. 888, its ability to abrogate these supply arrangements would be 
treated differently because its contracts do not meet the definition of 
a ``wholesale requirements contract,'' as defined in new section 
35.26(b)(1) of the Commission's Regulations. Public Service Co of CO 
further asserts that the Commission has not adequately explained why it 
is appropriate or in the public interest to allow partial requirements 
customers to abrogate their contracts, but not similarly to allow a 
public utility to abrogate its supply arrangements.<SUP>28
---------------------------------------------------------------------------

    \28\ See also PSE&G.
---------------------------------------------------------------------------

    PSE&G and Carolina argue that the availability of stranded cost 
recovery cannot support allowing customers to modify rates under 
Mobile-Sierra clauses that required that public-interest determination 
in the first place.
    PSE&G and Carolina P&L also argue that no Mobile-Sierra contracts 
entered into after October 24, 1992 (the date EPAct became law) should 
be subject to the Rule because since that date customers have been able 
to apply for an order under section 211 to have power transmitted to 
them from suppliers other than the utility to whom they are 
interconnected.
    PSE&G requests that the Commission clarify that the just and 
reasonable standard used in considering a contract abrogation claim 
will be limited to a determination of whether the rate is just and 
reasonable within the cost-based zone of reasonableness of the selling 
public utility. Such an analysis, PSE&G asserts, should not include a 
comparison to what other utilities offer to their customers.<SUP>29
---------------------------------------------------------------------------

    \29\ See also Carolina P&L.
---------------------------------------------------------------------------

Customers Seek Enhanced Contract Reformation Rights

    TAPS argues that the Commission should apply a just and reasonable 
standard to requests by all ``victims'' of undue discrimination to seek 
modifications of requirements or transmission contracts, whether they 
are subject to Mobile-Sierra or not. On the other hand, TAPS asserts 
that utilities should be bound to the bargain they extracted from 
transmission customers. Wisconsin Municipals request that the 
Commission clarify that parties may seek mandatory abrogation of 
preexisting transmission contracts or provisions and that the 
Commission will apply a rebuttable presumption that terms and 
conditions inferior to the pro forma tariff are unjust and unreasonable 
on their face.
    CCEM argues that requirements customers should receive blanket 
conversion rights. At a minimum, CCEM asserts, if a customer seeks 
conversion, the burden of proof in the proceeding should shift to the 
utility. CCEM also emphasizes that the question remains why conversion 
was deemed essential in natural gas markets, but not in the transition 
to competition in the electric industry.
    Blue Ridge argues:

    In neither the power supply nor transmission access case should 
a provider be allowed to modify existing power supply contracts 
under any but the Mobile Sierra public interest burden of proof. In 
both the power supply or transmission access cases, the Commission 
should articulate the suggested standards for what constitutes a 
prima facia case. [<SUP>30]
---------------------------------------------------------------------------

    \30\ Blue Ridge at 16.
---------------------------------------------------------------------------

Commission Conclusion

    Before responding to the rehearing arguments raised, we wish to 
clarify our Mobile-Sierra findings. We explained in Order No. 888 that 
we were making two

[[Page 12285]]

complementary public interest findings. First, as discussed further in 
Section IV.J, we found that it is in the public interest to permit 
public utilities to seek stranded cost amendments to existing 
requirements contracts with Mobile-Sierra clauses. Second, we found 
that a ``party'' to a requirements contract containing a Mobile-Sierra 
clause no longer will have the burden of establishing independently 
that it is in the public interest to permit the modification of such 
contract, but still will have the burden of establishing that such 
contract no longer is just and reasonable and therefore ought to be 
modified. We clarify that, in making this second finding, our reference 
to a ``party'' to a requirements contract containing a Mobile-Sierra 
clause was directed at modification of contract provisions by 
customers. <SUP>31 Additionally, it applies to any contract revisions 
sought, whether or not they relate to stranded costs. <SUP>32
---------------------------------------------------------------------------

    \31\ We note that the fact that a contract may bind a utility to 
a Mobile-Sierra public interest standard does not necessarily mean 
that the customer is also bound to that standard. Unless a customer 
specifically waives its section 206 just and reasonable rights, the 
Commission construes the issue in favor of the customer. See Papago 
Tribal Utility Authority v. FERC, 723 F.2d 950, 954 (D.C. Cir. 
1983).
    \32\ In situations in which a customer institutes a section 206 
proceeding to modify a contract that binds the utility to a Mobile-
Sierra public interest standard, the utility may make whatever 
arguments it wants regarding any of the contract terms, including 
those unrelated to stranded costs, but will be bound to a Mobile-
Sierra public interest standard for contract terms that do not 
relate to stranded costs.
---------------------------------------------------------------------------

    In response to the Mobile-Sierra rehearing arguments described 
above, as well as the Mobile-Sierra arguments described in Section IV.J 
concerning our determinations regarding stranded cost amendments to 
contracts, the Commission believes it is important to first address the 
general context in which our Mobile-Sierra determinations have been 
made. In Order No. 888, the Commission removed the single largest 
barrier to the development of competitive wholesale power markets by 
requiring non-discriminatory open access transmission as a remedy for 
undue discrimination. This action carries with it the regulatory public 
interest responsibility to address the difficult transition issues that 
arise in moving from a monopoly, cost-based electric utility industry 
to an industry that is driven by competition among wholesale power 
suppliers and increasing reliance on market-based generation rates.
    There are two predominant, overlapping transition issues that arise 
as a result of our actions in this rulemaking: first, how to deal with 
the uneconomic sunk costs incurred, and second, how to deal with the 
contracts that were entered into, under an industry regime that rested 
on a regulatory framework and set of expectations that are being 
fundamentally altered. To address these issues, the Commission has 
balanced a number of important interests in order to achieve what it 
believes will be a fair and orderly transition to competitive markets. 
These interests include the financial stability of the electric utility 
industry and permitting customers to obtain the benefits of competitive 
markets without undue disruption or unfairness to other customers or 
industry participants.
    As the above rehearing arguments demonstrate, there is no consensus 
on how the Commission should manage the transition. In fact, parties 
offer diverse and conflicting views as to what the Commission should do 
regarding existing contracts. Some would have us let all contracts run 
their course with no opportunity for customers to modify or terminate 
their contracts, no matter how long the contracts or how onerous their 
terms. Others advocate automatic generic abrogation of all contracts. 
Yet others want a guaranteed automatic right to renew a contract if it 
happens to contain favorable rates and terms.<SUP>33
---------------------------------------------------------------------------

    \33\ Similarly, as discussed in Section IV.J, parties have taken 
extreme positions as to stranded cost recovery.
---------------------------------------------------------------------------

    Rather than adopting one extreme position or the other, the 
Commission has taken a measured approach with regard to contract 
modification, including modification of contracts that contain Mobile-
Sierra clauses. Our goal is to balance the desire to honor existing 
contractual arrangements with the need to provide some means to 
accelerate the opportunity of parties to participate in competitive 
markets. To accomplish this balance, the Commission, first, has made 
Mobile-Sierra public interest findings (discussed further below) only 
as to a limited set of contracts: those wholesale requirements 
contracts executed on or before July 11, 1994, which is the date of our 
first stranded cost proposed rulemaking and which served to put the 
industry and customers on notice that future contracts should 
explicitly address the rights, obligations and expectations of parties, 
including stranded cost obligations.<SUP>34
---------------------------------------------------------------------------

    \34\ As to existing economy energy coordination agreements, the 
Commission concludes that the evidence also supports its decision to 
condition future sales and purchase transactions that may occur 
under the ongoing umbrella coordination agreements. Specifically, we 
are requiring that the transmission service associated with these 
future transactions be provided pursuant to the Final Rule pro forma 
tariff. See Public Service Electric & Gas Company, 78 FERC para. 
61,119, slip op. at 4 and n.7 (1997).
---------------------------------------------------------------------------

    Second, with regard to contract modifications sought by utilities, 
as discussed in more detail in Section IV.J, utilities that seek to add 
stranded cost provisions have a high evidentiary burden to meet before 
they can add contract provisions that permit stranded cost recovery 
beyond the end of their contract terms; the burden is particularly high 
in the case of contracts with notice provisions. With regard to 
modifications of contract provisions that do not relate to stranded 
costs, a utility with a Mobile-Sierra contract clause will have the 
burden of showing that the provisions are contrary to the public 
interest.<SUP>35
---------------------------------------------------------------------------

    \35\ As discussed below, pre-July 11, 1994 contracts were 
entered into during an era in which transmission providers exerted 
monopoly control over access to their transmission facilities. The 
unequal bargaining power between utilities and captive customers is 
the basis for our determination that utilities that have pre-July 11 
Mobile-Sierra requirements contracts will have to satisfy the public 
interest standard in order to effectuate any non-stranded cost 
change to the contract, but that customers to such contracts will be 
able to effectuate any change by satisfying a just and reasonable 
standard.
---------------------------------------------------------------------------

    Third, with regard to contract modifications sought by customers, a 
customer will have to show that the provisions it seeks to modify are 
no longer just and reasonable.<SUP>36 If a customer seeks to shorten or 
eliminate the term of an existing contract, any contract modification 
approved by the Commission will take into account the issue of 
appropriate stranded cost recovery by the customer's supplying utility.
---------------------------------------------------------------------------

    \36\ We will not grant the request by PSE&G and Carolina P&L 
that the just and reasonable standard will be limited to a 
determination of whether the rate is just and reasonable within the 
cost-based zone of reasonableness of the selling utility and should 
not include a comparison to what other utilities offer their 
customers. Because stranded costs will be taken into account when 
customers seek contract termination or modification, it would not be 
appropriate to limit customers in the evidence they may present.
---------------------------------------------------------------------------

    In permitting customers the opportunity to seek these types of 
modifications, even for contracts that contain Mobile-Sierra clauses, 
the Commission has based its public interest findings on the 
unprecedented industry changes facing utilities and their customers. 
While, as we stated in the Final Rule, there is no market failure in 
the electric industry that would justify generic abrogation of existing 
contracts, nevertheless the industry is in the midst of fundamental 
change. We cannot conclude that it is in the public interest to require 
all customers to be

[[Page 12286]]

held to requirements contracts that were executed under the prior 
industry regime, no matter what the circumstances of those contracts.
    In response to parties who challenge the Commission's finding that 
it would be against the public interest to deny customers an 
opportunity to seek modification of wholesale requirements contracts 
executed on or before July 11, 1994,<SUP>37 these parties ignore the 
fact that these contracts were entered into during an era in which 
transmission providers exercised monopoly control over access to their 
transmission facilities.<SUP>38 The majority of customers under these 
types of contracts were captive, i.e., they had no realistic choice but 
to purchase generation from their local utility because they had no 
transmission to reach another supplier. Many of these contracts were 
the result of uneven bargaining power between customers and monopolist 
transmission providers.<SUP>39 While monopolist transmission providers 
may not have exercised monopoly power in all situations,<SUP>40 the 
unprecedented competitive changes that have occurred (and are 
continuing to occur) in the industry may render their contracts to be 
no longer in the public interest or just and reasonable. These changed 
circumstances, discussed at length in the Final Rule, and the further 
changes that will occur as a result of open access transmission, may 
affect whether such contracts continue to be just and reasonable or not 
unduly discriminatory both as to the direct customers of the contracts, 
as well as to indirect, third-party consumers as well.<SUP>41
---------------------------------------------------------------------------

    \37\ We note that some of the very parties making this challenge 
either do not object to the Commission's Mobile-Sierra findings 
permitting utilities to add stranded cost amendments to their 
contracts, or ask the Commission to broaden even further the scope 
of extra-contractual stranded cost recovery under the rule.
    \38\ We also reject arguments that a remedy is not needed 
because existing programs, i.e., those prior to Order No. 888, are 
meeting the needs of the industry. This very rulemaking, with the 
substantial comments filed by entities pointing out the failures of 
the current system and the need for change, and the extensive 
restructurings and state-initiated open access programs occurring 
around the country, on their face, refute these arguments.
    \39\ It is also clear from the number of entities filing 
comments on the NOPR and rehearing requests of the Final Rule that 
many entities believe that their contracts were the result of uneven 
bargaining power and that they should be provided the opportunity to 
seek to terminate their existing contracts.
    \40\ In an era that was not characterized by competition in the 
generation sector, the Commission's response was to ensure that the 
rates for such contracts were no higher than the seller's cost 
(including a reasonable return on equity). In this way, the 
Commission sought to limit the seller's ability to reap the benefits 
of the seller's monopoly position.
    \41\ See FPC v. Sierra Pacific Power Company, 350 U.S. 348, 355 
(1956); Northeast Utilities Service Company, 66 FERC para. 61,332 
(1994), aff'd, 55 F.3d 686, 691 (1st Cir. 1995); Mississippi 
Industries v. FERC, 808 F.2d 1525, 1553 (D.C. Cir. 1987).
---------------------------------------------------------------------------

    We therefore reject arguments that there is no ``evidence'' to 
support our finding that it is in the public interest to permit review 
of these contracts in light of the specific circumstances surrounding 
the contracts and in light of dramatically changed industry 
circumstances. We emphasize, however, that our decision is to permit an 
opportunity for review and that we will require a case-by-case showing 
that any modifications should be permitted. <SUP>42 As we explained in 
the Final Rule, this decision complements our decision that it is in 
the public interest to permit amendments to add stranded cost 
provisions to existing contracts if case-by-case evidentiary burdens 
are met.
---------------------------------------------------------------------------

    \42\ We will not exclude Mobile-Sierra contracts entered into 
after the effective date of EPAct, as argued by PSE&G and Carolina 
P&L. As we explained in the Final Rule, there are significant time 
delays associated with section 211 proceedings. Accordingly, the 
availability of a section 211 proceeding cannot substitute for 
readily available service under a filed non-discriminatory open 
access tariff. FERC Stats. & Regs. at 31,646; mimeo at 35. We do not 
believe that EPAct created the expectation of open access on such a 
broad scale that we can assume that parties no longer generally 
expected ``business as usual'' to continue, and we will not presume 
that the exercise of market power was not at work when Mobile-Sierra 
contracts were entered into after EPAct. We also note that these 
arguments are similar to those proffered by opponents of stranded 
cost recovery, who argue that after EPAct utilities had no 
reasonable expectation of continuing to serve customers beyond the 
terms of existing contracts. In this context as well, we will not 
presume that, after EPAct, utilities could have no reasonable 
expectation of continuing to serve a customer beyond the contract 
term.
---------------------------------------------------------------------------

    As we discuss further in our detailed stranded cost discussion in 
Section IV.J, we do not interpret the Mobile-Sierra public interest 
standard as practically insurmountable <SUP>43 in the extraordinary 
situation before us where historic statutory and regulatory changes 
have converged to fundamentally change the obligations of utilities and 
the markets in which both they and their customers will operate. The 
ability to meet our overarching public interest responsibilities and to 
protect consumers would be virtually precluded if we were to apply a 
practically insurmountable standard of review before taking into 
account these fundamental industry-wide changes.<SUP>44
---------------------------------------------------------------------------

    \43\ As the D.C. Circuit explained in Papago Tribal Utility 
Authority v. FERC, 723 F.2d 950 (D.C. Cir. 1983) (Papago), there are 
essentially three contractual arrangements for rate revision: (1) 
the parties agree that the utility may file new rates under section 
205, subject to the just and reasonable standard of review; (2) the 
parties agree to eliminate the utility's right to file rates under 
section 205 and the Commission's right to change pre-existing rates 
under section 206's just and reasonable standard (leaving the 
Commission's indefeasible right to change pre-existing rates that 
are contrary to the public interest); and (3) the parties agree to 
eliminate the utility's right to file new rates under section 205, 
but leave unaffected the Commission's power to change pre-existing 
rates under section 206's just and reasonable standard of review. 
723 F.2d at 953. The same contractual arrangements also would apply 
to non-rate terms and conditions. We here address those contractual 
arrangements that eliminate the rights of one or both parties to 
modify a contract under the just and reasonable standard. We note 
that the Commission always has the indefeasible right under section 
206 to change rates, terms or conditions that are contrary to the 
public interest. 723 F.2d at 953-55; see also Florida Power & Light 
Company, 67 FERC para. 61,141 at 61,398 (1994) appeal dismissed, No. 
94-1483 (D.C. Cir. July 27, 1995) (unpublished); Southern Company 
Services, Inc., 67 FERC para. 61,080 at 61,227-28 (1994); 
Mississippi Industries v. FERC, 808 F.2d 1525, 1552 n.112.
    \44\ We reject the arguments of PSE&G and Carolina P&L that we 
have failed to demonstrate the ``unequivocal public necessity'' for 
generically ``abrogating'' Mobile-Sierra clauses and that we have 
presented no evidence as to how the public interest will be served 
by abrogating these contracts. We have concluded that there is a 
public necessity to permit the opportunity to seek contract changes 
in light of fundamental industry changes. However, we have not 
abrogated any contracts by this Rule.
---------------------------------------------------------------------------

    With respect to Public Service Co of CO's argument, we disagree 
that the definition of a wholesale requirements contract should be 
modified to include a long-term block purchase of electricity. In the 
majority of circumstances, such long-term supply contracts are 
voluntary arrangements in which neither party had market power. It 
would be inappropriate to make generic Mobile-Sierra findings as to 
these types of contracts. Parties can avail themselves of the section 
205 and 206 procedures already available to them if they want to seek 
modification of such contracts.
    Finally, we reject CCEM's argument that all customers should 
receive automatic conversion rights because customers were provided 
such a right in the restructuring of the natural gas industry. We have 
taken, as is within our discretion, a substantially different approach 
here from that taken when we restructured the natural gas industry. As 
we stated in the Final Rule, and as alluded to above, at the time the 
Commission addressed this situation in the natural gas industry it was 
faced with shrinking natural gas markets, statutory escalations in 
natural gas ceiling prices under the Natural Gas Policy Act, and 
increased production of gas.\45\ Moreover, the natural gas industry was 
plagued with escalating take-or-pay liabilities.
---------------------------------------------------------------------------

    \45\ FERC Stats. & Regs. at 31,664; mimeo at 84.
---------------------------------------------------------------------------

    There was a market failure in the natural gas industry that 
required the

[[Page 12287]]

extraordinary measure of generically allowing all customers to break 
their contracts with pipelines. In contrast, market circumstances in 
the electric industry today do not compel generic abrogation of 
contracts. The more moderate approach we have taken will permit us to 
take into account the fundamental industry changes that have occurred 
(and will continue to occur), to balance the interests of all affected 
parties, and to help avoid drastic shocks to industry participants.

Right of First Refusal

    In the Final Rule, the Commission concluded that all firm 
transmission customers (requirements and transmission-only), upon the 
expiration of their contracts or at the time their contracts become 
subject to renewal or rollover, should have the right to continue to 
take transmission service from their existing transmission 
provider.\46\ If not enough capacity is available to meet all requests 
for service, the right of first refusal gives the existing customer who 
had contractually been using the capacity on a long-term, firm basis 
the option of keeping the capacity. However, the limitations imposed by 
the Commission are that the underlying contract must have been for a 
term of one-year or more and the existing customer must agree to match 
the rate offered by another potential customer, up to the transmission 
provider's maximum filed transmission rate at that time, and to accept 
a contract term at least as long as that offered by the potential 
customer.\47\ Moreover, the Commission indicated that this right of 
first refusal is an ongoing right that may be exercised at the end of 
all firm contract terms (including all future unbundled transmission 
contracts).
---------------------------------------------------------------------------

    \46\ FERC Stats. & Regs. at 31,665; mimeo at 88.
    \47\ The Commission explained that this right of first refusal 
exists whether or not the customer buys power from the historical 
utility supplier or another power supplier. If the customer chooses 
a new power supplier and this substantially changes the location or 
direction of its power flows, the customer's right to continue 
taking transmission service from its existing transmission provider 
may be affected by transmission constraints associated with the 
change.
---------------------------------------------------------------------------

Requests for Rehearing

    On rehearing, most petitioners agree with or do not contest the 
notion of providing existing transmission customers with a right of 
first refusal, but many have requested modification or clarification of 
the Commission-imposed limitations on such a right. A variety of 
transmission customers assert that the Commission's right of first 
refusal provision fails to adequately protect existing transmission 
customers' rights to continued service and seek changes to the 
Commission's provision. On the other hand, a number of utilities 
believe that the Commission should provide additional restrictions on 
the right of first refusal.

Customers' Positions

    APPA argues that (1) existing customers should only have to agree 
to service that matches the term of any power supply contract for which 
it will use the transmission arrangement or, in the absence of a 
generation contract, one year, and (2) the pricing provision should be 
changed to reflect the current just and reasonable rate, as approved by 
the Commission, for similar transmission service.
    NRECA also argues that the term and pricing provisions of section 
2.2 need to be changed. With respect to the term of the contract the 
customer should be required to match, NRECA asserts that it should be 
one year, which corresponds to the definition of long-term firm service 
in the tariff. With respect to the rate, NRECA requests that the 
Commission cap the obligation to match the price offered by another 
customer at the maximum transmission rate the incumbent customer is 
obligated to pay to the transmission provider at the close of the prior 
contract term.
    TDU Systems argue that the right of first refusal provision fails 
to take into consideration amounts that TDUs have contributed to the 
development of the transmission systems through prior transmission 
rates. TDU Systems are concerned about the possibility of an increase 
in the price of transmission capped only by the cost of increasing the 
capacity of the provider's transmission system.
    TAPS requests that the Commission clarify that the transmission 
provider may only charge its then effective rates for existing, non-
constrained transmission capacity because to allow opportunity or 
expansion costs would perpetually put the existing transmission 
customers on the margin at the end of their contract terms subjecting 
them to higher rates than the transmission provider.\48\
---------------------------------------------------------------------------

    \48\ See also AEC & SMEPA.
---------------------------------------------------------------------------

    Blue Ridge raises a possible discrepancy between the language in 
the tariff and the language in the preamble. It asserts that section 
2.2 ``requires the existing customer to `pay the current just and 
reasonable rate, as approved by the Commission,' while the Regulatory 
Preamble requires the customer to `match the rate offered by another 
potential customer, up to the transmission provider's maximum filed 
transmission rate at that time.' Order No. 888, mimeo at 88.''
    Tallahassee asks the Commission to clarify that the right of first 
refusal to presently bundled transmission capacity accrues to the power 
customer paying the bundled rate and not to the intermediary acting on 
behalf of the customer.
    AEC & SMEPA maintain that the price and term limitations of section 
2.2 would place TDUs at a competitive disadvantage vis-a-vis the 
transmission provider by subjecting TDUs to incremental costs, 
including the costs of system upgrades, if other new customers are 
vying to use the transmission system. They state that the Commission 
must provide existing transmission customers the same rights as the 
transmission provider's other native load customers.

Utilities' Positions

    PSNM argues that imposing a right of first refusal is inconsistent 
with the Commission's finding that contracts should not be abrogated. 
In effect, it argues that imposition of the right of first refusal 
abrogates existing contracts executed with the expectation that 
capacity could be recalled for the utility's own use upon expiration of 
the contracts. PSNM explains that it has a constrained transmission 
system and has been balancing specific contract durations against 
projected future native loads so that required capacity may be made 
available for use by third parties in the short-term, but not be 
committed to those parties at the time it is needed to be recalled. 
Moreover, PSNM asserts that Order No. 888 is not supported by the right 
of first refusal process of Order No. 636 because the Commission does 
not have abandonment authority under the FPA and its authority to 
require continuation of service is not well-defined and is 
controversial.\49\
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    \49\ All transmission contracts with public utility transmitters 
can only be terminated by a filing with the Commission under FPA 
section 205. Thus, the Commission has interpreted its section 205 
authority as permitting it to suspend termination of service for 5 
months beyond the expiration of a contract's term if such action is 
necessary to protect ratepayers. See, e.g., Kentucky Utilities 
Company, 67 FERC para. 61,189 at 61,573 (1994). (While the 
termination procedures for power sales contracts executed after July 
9, 1996 were modified in Order No. 888, there were no changes 
regarding termination procedures for transmission contracts.).
---------------------------------------------------------------------------

    Utilities For Improved Transition and Florida Power Corp argue that 
section 2.2 of the pro forma tariff should be modified by ``restricting 
rollover rights to the same points of receipt and delivery as the 
terminating service and

[[Page 12288]]

by providing the customer notice of a competing application and 90 days 
in which to file its own application for service for a term at least as 
long as the competing application.'' (Florida Power Corp at 11-13; 
Utilities For Improved Transition at 50-53). Similarly, EEI argues that 
to obtain a priority for continuation of service, customers must be 
seeking service that is substantially similar to or a continuation of 
the service they already receive and must be subject to a time limit on 
the reservation priority. CSW Operating Companies assert that it is 
unclear how the right of first refusal provision will be implemented.

State Commission Position

    VT DPS states that the right of first refusal provision offers 
inadequate protection: ``While it is true that the existing customer 
could secure a five year transmission arrangement under a new contract, 
its right to continuous service is placed in jeopardy if it does not 
match the six year offer of the competing bidder.'' VT DPS argues that 
the Commission's bare bones provision opens the opportunity for 
competitive mischief by the transmission provider. VT DPS proposes that 
``the existing customer should be able to renew its contract by 
matching the highest transmission price offered in the marketplace (up 
to the tariff maximum rate) and by offering to extend its contract for 
seven years or the prevailing length of firm transmission contracts in 
the marketplace, whichever is shorter.'' (VT DPS at 17-21).

Commission Conclusion

    In this order, the Commission reaffirms its decision to give a 
reservation priority to existing and future firm transmission customers 
served under a contract of one year or more, and also addresses 
petitioner arguments regarding the Commission-imposed limitations 
associated with the exercise of that priority.

Rationale

    Our policy rationale for giving an existing firm transmission 
customer (requirements and transmission-only),\50\ served under a 
contract of one year or more, a reservation priority (right of first 
refusal) when its contract expires is that it provides a mechanism for 
allocating transmission capacity when there is insufficient capacity to 
accommodate all requestors. If there are capacity limitations and both 
customers (existing and potential) are willing to pay for firm 
transmission service of the same duration, the right of first refusal 
provides a tie-breaking mechanism that gives priority to existing 
customers so that they may continue to receive transmission 
service.\51\
---------------------------------------------------------------------------

    \50\ We clarify that we did not intend the term ``all firm 
transmission customers'' to include only requirements and 
transmission-only customers, but intended that it include all 
bundled firm customers as well.
    \51\ We reject Tallahassee's argument that the right of first 
refusal should accrue to the power customer paying the bundled rate 
and not to any intermediary acting on its behalf. Our right of first 
refusal mechanism is simply a tie-breaker that gives priority to 
existing firm transmission customers.
---------------------------------------------------------------------------

Contract Term Limitation

    We reject arguments to modify the requirement in section 2.2 that 
existing long-term firm transmission customers seeking to exercise 
their right of first refusal must agree to a contract term at least as 
long as that sought by a potential customer. The objective of a right 
of first refusal is to allow an existing firm transmission customer to 
continue to receive transmission service under terms that are just, 
reasonable, not unduly discriminatory, or preferential. Absent the 
requirement that the customer match the contract term of a competing 
request, utilities could be forced to enter into shorter-term 
arrangements that could be detrimental from both an operational 
standpoint (system planning) and a financial standpoint.

Rate Limitation

    We also reject the proposition that either existing wholesale 
customers or transmission providers providing service to retail native 
load customers should be insulated from the possibility of having to 
pay an increased rate for transmission in the future. The fact that 
existing customers historically have been served under a particular 
rate design does not serve to ``grandfather'' that rate methodology in 
perpetuity. Because the purpose of the right of first refusal provision 
is to be a tie-breaker, the competing requests should be substantially 
the same in all respects.\52\
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    \52\ The proposal to restrict the right of first refusal 
provision to exactly the same points of receipt and delivery as the 
terminating service would competitively disadvantage existing 
customers seeking new sources of generation. However, as we stated 
in Order No. 888, if the customer chooses a new power supplier and 
this substantially changes the location or direction of the power 
flows it imposes on the transmission provider's system, the 
customer's right to continue taking transmission service from its 
existing transmission provider may be affected by transmission 
constraints associated with the change. FERC Stats. & Regs. at 
31,666 n.176; mimeo at 89 n.176.
---------------------------------------------------------------------------

    In response to Blue Ridge's concern regarding a discrepancy between 
the language in section 2.2 of the tariff and the preamble, we clarify 
that existing customers who exercise their right of first refusal will 
be required to pay the just and reasonable rate, as approved by the 
Commission at the time that their contract ends.\53\
---------------------------------------------------------------------------

    \53\ As Order No. 888 indicates, they may be required to pay the 
transmission provider's maximum transmission rate.
---------------------------------------------------------------------------

Mechanics of the Right of First Refusal Process

    CSW Operating Companies asked the Commission to clarify the 
mechanics of exercising the right of first refusal. We have determined 
not to specify in this order the mechanics by which the right of first 
refusal mechanism will be exercised for existing firm transmission 
arrangements. Instead, we intend to address such issues on a case-by-
case basis, if and when a dispute arises. However, we encourage 
utilities and their customers to include specific procedures for 
exercising the right of first refusal in future transmission service 
agreements executed under the pro forma tariff. And of course, 
utilities are free to make section 205 filings to propose additions to 
the pro forma tariff to generically specify procedures for dealing with 
the issues.

Existing Contracts

    By providing existing customers a right of first refusal, we are 
not, as PSNM claims, abrogating contracts. Moreover, PSNM's concern 
that the right of first refusal will prohibit utilities from 
``recalling'' existing capacity to meet native load growth that was 
anticipated at the time existing third-party transmission contracts 
were executed can be addressed in the context of a specific filing by a 
utility demonstrating that it had no reasonable expectation of 
continuing to provide transmission service to the wholesale 
transmission customer at the end of its contract. For future 
transmission contracts, Order No. 888 permits utilities to reserve 
existing transmission capacity to serve the needs (current and 
reasonably forecasted) of its existing native load (retail) customers. 
Moreover, if a utility provides firm transmission service to a third 
party for a time until native load needs the capacity, it should 
specify in the contract that the right of first refusal does not apply 
to that firm service due to a reasonably forecasted need at the time 
the contract is executed.

Informational Filings

    With respect to all existing requirements contracts and tariffs 
that provide for bundled rates, the Commission, in the Final Rule, 
required all public utilities to make informational

[[Page 12289]]

filings setting forth the unbundled power and transmission rates 
reflected in those contracts and tariffs.<SUP>54
---------------------------------------------------------------------------

    \54\ FERC Stats. & Regs. at 31,665-66; mimeo at 89-90.
---------------------------------------------------------------------------

Requests for Rehearing

    Utilities For Improved Transition and VEPCO ask the Commission to 
clarify whether the unbundled transmission rate should be the current 
transmission tariff rate (bundled rate likely not to include the 
current price for transmission service) or an approximation of the rate 
at the time the contract was executed (may be impossible to determine).

Commission Conclusion

    We previously addressed the determination of the unbundled 
transmission rate in informational filings in an order issued October 
16, 1996.<SUP>55 In that order, we noted that Order No. 888 does not 
prescribe any specific method for calculating separately-stated 
transmission and generation rates and public utilities have used 
different methods in their informational filings. Because of the 
general lack of controversy over the informational filings and the fact 
that they are for informational purposes as a benefit to existing 
customers, the Commission accepted the vast majority of the 
informational filings. The Commission added, however, that it did not 
consider the informational rates binding for any future transactions. 
Accordingly, we need not now prescribe a specific method to calculate 
the unbundled transmission rate included in informational filings.
---------------------------------------------------------------------------

    \55\ 77 FERC para. 61,025.
---------------------------------------------------------------------------

Existing Contracts

    In the Final Rule, the Commission explained that because it was not 
abrogating existing requirements and transmission contracts generically 
and because the functional unbundling requirement applies only to new 
wholesale services, the terms and conditions of the Final Rule pro 
forma tariff do not apply to service under existing requirements 
contracts.<SUP>56
---------------------------------------------------------------------------

    \56\ FERC Stats. & Regs. at 31,665; mimeo at 87-88.
---------------------------------------------------------------------------

Rehearing Requests

    San Francisco asks that the Commission clarify that nothing in 
Order No. 888 is intended to affect prices, or price-setting 
methodologies, in existing contracts.

Commission Conclusion

    By order issued July 2, 1996, we clarified that

    the filing of an open access compliance tariff on or before July 
9, 1996 does not supersede an existing transmission agreement that 
has been accepted by the Commission unless specifically permitted in 
the agreement on file. If a utility seeks to modify or terminate an 
existing transmission agreement, it must separately file to modify 
or terminate such contracts under appropriate procedures under 
section 205 or 206 of the Federal Power Act, consistent with the 
terms of its contract.[<SUP>57]

    \57\ 76 FERC para. 61,009 at 61,028 (1996).
---------------------------------------------------------------------------

    Thus, nothing in Order No. 888 affects prices or price-setting 
methodologies in existing contracts, unless specifically permitted in 
the contract on file.
6. Flow-based Contracting and Pricing
    In Order No. 888, the Commission explained that it would not, at 
that time, require that flow-based pricing and contracting be used in 
the electric industry.<SUP>58 It recognized that there may be 
difficulties in using a traditional contract path approach in a non-
discriminatory open access transmission environment. At the same time, 
however, the Commission noted that contract path pricing and 
contracting is the longstanding approach used in the electric industry 
and it is the approach familiar to all participants in the industry. 
Thus, the Commission was concerned that to require a dramatic overhaul 
of the traditional approach--such as a shift to some form of flow-based 
pricing and contracting--could severely slow, if not derail for some 
time, the move to open access and more competitive wholesale bulk power 
markets. In addition, the Commission indicated its belief that it would 
be premature to impose generically a new pricing regime without the 
benefit of any experience with such pricing. Accordingly, the 
Commission welcomed new and innovative proposals, but determined not to 
impose some form of flow-based pricing or contracting in the Final 
Rule.
---------------------------------------------------------------------------

    \58\ FERC Stats. & Regs. at 31,668; mimeo at 96-98.
---------------------------------------------------------------------------

Rehearing Requests

    American Forest & Paper argues that contract path pricing should be 
prohibited. American Forest & Paper asserts that QFs and other 
independents are being forced by contract path wheeling utilities to 
indemnify them from liability for third-party claims of inadvertent 
flow costs resulting from the transaction, while paying postage stamp 
rates for the entire amount of contracted transmission. American Forest 
& Paper supports an average postage stamp rate by region, with the 
utilities within the region agreeing on a way to divide up the rate 
appropriately.

Commission Conclusion

    As the Commission explained in the Final Rule, we are concerned 
that a dramatic overhaul of the traditional contract path approach 
could slow or derail the move to open access and, in any event, is 
premature without the benefit of any experience with alternative 
pricing regimes. The Commission, however, welcomes new and innovative 
proposals from the industry. American Forest & Paper has not presented 
a case-specific proposal of any detail that would provide the 
Commission and interested parties the opportunity to test the 
appropriateness of a change from the contract path approach. Until the 
Commission has such an opportunity, we are not prepared to change 
generically the traditional contract path approach with which the 
electric industry is so familiar.
    Moreover, American Forest & Paper's proposal to prohibit contract 
path pricing and mandate regional postage-stamp rates would be 
inconsistent with the rate flexibility that the Commission provided in 
the Transmission Pricing Policy Statement and embraced in the Final 
Rule.

B. Legal Authority

    In the Final Rule, the Commission responded to commenters 
challenging the Commission's authority to require open access and 
reaffirmed its conclusion in the NOPR that it has the authority under 
the FPA to order wholesale transmission services in interstate commerce 
to remedy undue discrimination by public utilities.<SUP>59
---------------------------------------------------------------------------

    \59\ FERC Stats. & Regs. at 31,668-79 and 31,686-87; mimeo at 
98-129 and 148-51.
---------------------------------------------------------------------------

Rehearing Requests

Authority To Order Open Access Tariffs

    Union Electric challenges the Commission's authority to require 
wheeling based on arguments that: (1) the Rule overlooks the fact that 
the AGD case <SUP>60 pertained to voluntary actions by the pipelines 
and the Commission's imposition of open access requirements as a 
condition on permitting the desired authorizations; (2) the Commission 
incorrectly treats the Otter Tail case; <SUP>61 (3) the legislative 
histories of the NGA and FPA are different and the legislative history 
of the FPA does not support the Commission's authority to order 
wheeling; (4) the Commission made prior contrary statements to the U.S.

[[Page 12290]]

Supreme Court [in its opposition to the grant of certiorari to review 
the AGD decision] about the nature of Commission authority to order 
open access and judicial construction of that authority in AGD and 
Otter Tail;'' (5) as a matter of statutory construction, the Commission 
cannot rely on sections 205 and 206, which are silent as to wheeling, 
when sections 211 and 212 contain express wheeling provisions; (6) the 
four relevant cases recognized by the Commission indicate that the 
Commission may not directly or indirectly order a public utility to 
wheel or transmit energy for another entity under sections 205 and 206, 
notwithstanding the Commission's circumscribed ability to order 
wheeling under sections 211 and 212; (7) prior to the issuance of the 
Final Rule the Commission, with a full appreciation of the legislative 
history behind Part II, consistently held that it lacks the authority 
to order wheeling under FPA Part II; (8) the Rule fails to assign 
``considerable importance'' to the Commission's ``longstanding 
interpretation of the statute in accordance with its literal 
language;'' and (9) in legislative hearings preceding enactment of 
EPAct, the Office of the General Counsel acknowledged the limitations 
on the Commission's wheeling power.
---------------------------------------------------------------------------

    \60\ Associated Gas Distributors v. FERC, 824 F.2d 981, 998 
(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD).
    \61\ Otter Tail Power Company v. FPC, 410 U.S. 366 (1974) (Otter 
Tail).
---------------------------------------------------------------------------

    Carolina P&L also challenges the Commission's authority to order 
open access tariffs, arguing that: (1) Otter Tail specifically states: 
``So far as wheeling is concerned, there is no authority granted the 
commission under Part II of the Federal Power Act to order it, * * *''; 
(2) the Richmond and FPL cases <SUP>62 prohibit the Commission from 
doing indirectly what it cannot do directly; (3) the AGD case does not 
support the Commission's authority to order open access through the 
filing of generic tariffs--in AGD the Commission's authority was based 
on voluntary actions by the affected pipelines and there are 
substantial differences between the NGA and the FPA; (4) the 
legislative history of EPAct indicates that the Commission does not 
have the authority to mandate open access and can only order open 
access if section 211 procedures are followed--citing NYSEG and FPL; 
and (5) section 211 limits the Commission's authority to order open 
access on a generic basis--where a specific statute addresses an issue, 
a more general statute should not be read in a manner that conflicts 
with the specific statute.
---------------------------------------------------------------------------

    \62\ Richmond Power & Light Company v. FERC, 574 F.2d 610 (D.C. 
Cir. 1978) (Richmond) and Florida Power & Light Company v. FERC, 660 
F.2d 668 (5th Cir. 1981), cert. denied sub nom. Fort Pierce 
Utilities Authority v. FERC, 459 U.S. 1156 (1983) (FPL).
---------------------------------------------------------------------------

    PA Com argues that the Commission's reliance on AGD ``impermissibly 
expands the limited holding of AGD'' and the Commission improperly 
relied on sections 205 and 206 of the FPA to require open access 
generically--the Commission only has case-by-case jurisdiction.
    VA Com declares that the plain meaning of the FPA and cases 
interpreting sections 206 and 211 show that the Commission does not 
have the authority to order industry-wide open access.
    FL Com and El Paso argue that the Commission only has limited 
authority to order wheeling and that the Commission has not made the 
required findings under section 211.\63\
---------------------------------------------------------------------------

    \63\ We note that Indianapolis P&L also has made legal arguments 
regarding our authority to order wheeling under Order No. 888. 
However, it did so in a request for rehearing of a denial of its 
request for waiver of the Order No. 888 requirements, not in its 
request for rehearing of Order No. 888. Accordingly, we will address 
its arguments when we act on its request for rehearing of its waiver 
denial.
---------------------------------------------------------------------------

Group Two Section 205 Filings

    Union Electric argues that the requirement that Group 2 Public 
Utilities make section 205 filings is contrary to the voluntary filing 
scheme inherent in section 205.

Commission Conclusion

Overview

    The fundamental legal question before us is the scope of the 
authority granted to the Commission in 1935 to remedy undue 
discrimination in interstate transmission services and whether that 
authority permits us sufficient flexibility to define undue 
discrimination in light of dramatically changed industry circumstances, 
in order to provide electricity customers the benefits of more 
competitively priced power. In the NOPR and Order No. 888, the 
Commission comprehensively examined case law and legislative history 
relevant to our authority to order open access transmission services as 
a remedy for undue discrimination.\64\ We also responded at length in 
Order No. 888 to arguments that questioned our authority to take this 
step.\65\
---------------------------------------------------------------------------

    \64\ FERC Stats. & Regs. at 31,668-73; mimeo at 98-112. Notice 
of Proposed Rulemaking and Supplemental Notice of Proposed 
Rulemaking, FERC Stats. & Regs. para. 32,514 at 33,053-56 (1995).
    \65\ FERC Stats. & Regs. at 31,673-79; mimeo at 112-129.
---------------------------------------------------------------------------

    On rehearing, as described above, only a few parties continue to 
question the Commission's authority. As a general matter their 
rehearings do not raise any arguments, cases, or legislative history 
not previously considered, and they do not convince us that our action 
in Order No. 888 is not within our authority under sections 205 and 206 
of the FPA. We therefore reaffirm our determination that we have not 
only the legal authority, but the responsibility, to order the filing 
of non-discriminatory open access tariffs if we find such order 
necessary to remedy undue discrimination or anticompetitive effects.
    There are several broad points we wish to emphasize in response to 
the rehearings that have been filed:
    First, there is no dispute that the FPA does not explicitly give 
this Commission authority to order, sua sponte, open access 
transmission services by public utilities. However, the fact remains 
that the FPA does explicitly require this Commission to remedy undue 
discrimination by public utilities.\66\ The finding of the D.C. Circuit 
in the AGD case, with regard to sections 4 and 5 of the NGA (which 
parallel sections 205 and 206 of the FPA), are equally applicable here: 
the Act ``fairly bristles'' with concerns regarding undue 
discrimination and it would turn statutory construction on its head to 
let the failure to grant a general power prevail over the affirmative 
grant of a specific one.\67\
---------------------------------------------------------------------------

    \66\ See FERC Stats. & Regs. at 31,669-70; mimeo at 101-03.
    \67\ 824 F.2d at 998.
---------------------------------------------------------------------------

    Second, there also is no dispute that before Congress enacted the 
FPA in 1935, it rejected provisions that would have explicitly granted 
the Commission authority to order transmission to any person if the 
Commission found it ``necessary or desirable in the public interest.'' 
However, the fact that Congress rejected an extremely broad common 
carrier provision does not limit the remedies available to the 
Commission to enforce the undue discrimination provisions in the 
FPA.\68\
---------------------------------------------------------------------------

    \68\ See FERC Stats. & Regs. at 31,676-78; mimeo at 120-27.
---------------------------------------------------------------------------

    Third, entities on rehearing understandably have focused on 
statements in case law that indicate limits on the Commission's 
wheeling authority. They particularly focus on certain statements by 
the Supreme Court in Otter Tail. The Commission in Order No. 888 fully 
addressed and considered all relevant case law of which we are aware, 
including statements in Otter Tail and other court cases indicating 
limitations on our authority.\69\ We do not dispute these statements 
and we

[[Page 12291]]

recognize limitations on our authorities. However, the fact remains 
that none of the cases cited, including Otter Tail, involved the issue 
of whether this Commission can order transmission as a remedy for undue 
discrimination and none addressed industry-wide circumstances such as 
those before us in Order No. 888.
---------------------------------------------------------------------------

    \69\ See FERC Stats. & Regs. at 31,668-73; mimeo at 98-110.
---------------------------------------------------------------------------

    Fourth, while Congress in 1978 gave the Commission certain case-by-
case authority to order transmission access by both public utilities 
and non-public utilities, and broadened this case-by-case authority in 
1992, Congress also specifically provided in section 212(e) of the FPA 
that the case-by-case authorities were not to be construed as limiting 
or impairing any authority of the Commission under any other provision 
of law.\70\ Indeed, the legislative history of EPAct shows that when 
Congress amended the section 211-212 wheeling provisions and the 
section 212(e) savings clause in 1992,\71\ it was well aware of 
arguments regarding the scope of the Commission's wheeling authority as 
a remedy for undue discrimination under section 206. Whereas Congress 
in 1992 decided to add a flat prohibition on the Commission ordering 
direct retail wheeling under any provision of the FPA, it did not add a 
prohibition on the Commission ordering wholesale wheeling to remedy 
undue discrimination under section 206. It instead retained and 
modified the savings clause. The issue before us, therefore, hinges on 
the scope of authority given to this Commission to remedy undue 
discrimination, not on the scope of authority given to us in 1978 and 
1992.
---------------------------------------------------------------------------

    \70\ See FERC Stats. & Regs. at 31,686-87; mimeo at 148-49.
    \71\ The savings clause in section 212(e) originally provided 
that no provision of section 210 or 211 shall be treated as 
``limiting, impairing, or otherwise affecting any authority of the 
Commission under any other provision of law.'' In 1992, the 212(e) 
savings clause was amended to provide that sections 210, 211 and 214 
``shall not be construed as limiting or impairing any authority of 
the Commission under any other provision of law.''
---------------------------------------------------------------------------

    The Commission is significantly influenced by the decision and case 
law discussion by the D.C. Circuit in the AGD case. This court opinion 
contains the most recent and comprehensive discussion of the 
Commission's legal authority to remedy undue discrimination under NGA 
provisions that mirror those in the FPA, including the relevant case 
law concerning the Commission's authority to order transmission under 
the FPA.\72\ The rehearing arguments do not, and we believe cannot, 
reconcile the AGD court's discussion and findings with a conclusion 
that the Commission cannot under any circumstances (as these parties 
advocate) order wheeling under sections 205 and 206 to remedy undue 
discrimination.
---------------------------------------------------------------------------

    \72\ AGD, 824 F.2d at 996-999. See also FERC Stats. & Regs. at 
31,668-73, 31,676-78; mimeo at 98-110 and 120-27.
---------------------------------------------------------------------------

    In sum, we believe that the essential question of the Commission's 
legal authority to impose the requirements of Order No. 888 turns on 
the flexibility of the Commission's remedial authority under sections 
205 and 206 of the FPA to remedy undue discrimination. As was true with 
respect to the natural gas industry, we acknowledge that Commission 
precedent for many years nurtured the expectation that we would not, 
under our authority under the FPA, preclude utilities from using their 
monopoly power over the nation's transmission systems to secure their 
monopoly position as power suppliers. However, as described at length 
in Order No. 888, these policies arose in the context of practical, 
economic, and regulatory circumstances that gave rise to vertically 
integrated monopolies and little, if any, competition among power 
suppliers. In this kind of regime, the interests of customers were most 
effectively served by the kind of cost-based regulatory regime that has 
prevailed until very recently. The evolution of third-party generation, 
facilitated by PURPA and significant technological advances, 
dramatically altered the economics of power production. The enactment 
of EPAct recognized these changes and established a national policy 
intended to favor the development of a competitive generation market, 
so that the efficiencies of the new marketplace will be available to 
customers in the form of lower costs for electricity. Utility practices 
that may have been acceptable a few years ago would, if permitted to 
continue, smother the fledgling competitive wholesale markets and 
undermine the efforts of customers to seek lower-price electricity. We 
firmly believe that our authorities under the FPA not only permit us to 
adapt to changing economic realities in the electric industry, but also 
require us to do so, if that is necessary to eliminate undue 
discrimination and protect electricity customers.

Specific Arguments \73\

The Factual Circumstances Underlying AGD Do Not Mandate A Different 
Conclusion In This Proceeding

    Both Union Electric and Carolina P&L argue that the Commission 
cannot rely on AGD in support of its actions in the electric industry, 
and they attempt to distinguish the legal basis on which the Commission 
acted in requiring open access transportation for gas pipelines. 
Specifically, they argue that AGD (Order No. 436) pertained to 
voluntary actions by gas pipelines and that the Commission's imposition 
of open access requirements was a condition of certificate 
authorizations to transport gas, whereas the Commission's action in 
Order No. 888 is a direct mandate.\74\ We believe this is a distinction 
without a difference. While it is true that the Commission required 
open access as a condition of granting blanket authorizations for 
pipelines and authorizations for pipelines authorizing pipelines to 
transport natural gas,\75\ the critical point is that in both Order No. 
436 and Order No. 888 the Commission's actions hinged as a legal matter 
on the parallel provisions of the NGA (sections 4 and 5) and the FPA 
(sections 205 and 206) that prohibit undue discrimination. Whether 
persons are seeking to transport natural gas or wheel electric power in 
interstate commerce, by law they must not unduly discriminate or grant 
undue preference.\76\
---------------------------------------------------------------------------

    \73\ We do not repeat our lengthy legal analyses in Order No. 
888, but discuss only those arguments that warrant further 
discussion.
    \74\ See Union Electric and Carolina P&L.
    \75\ These authorizations are issued under section 7 of the 
Natural Gas Act and section 311 of the Natural Gas Policy Act.
    \76\ While there is a difference in the statutes in that natural 
gas transporters must obtain a certificate from the Commission 
before they can transport gas, there is no difference in the 
statutory standard applied to the interstate service.
---------------------------------------------------------------------------

    In AGD, the court upheld the Commission's reliance upon sections 4 
and 5 of the NGA to impose an open-access commitment on any pipeline 
that secured a blanket certificate to provide gas transportation under 
section 7 of the NGA or provided transportation under section 311 of 
the NGPA.\77\ Order No. 436 was not a simple order that relied on the 
``voluntary actions'' of affected pipelines. As the court in AGD 
understood:

    \77\ 824 F.2d at 997-98. The court also noted the Commission's 
reliance on section 16 of the NGA.
---------------------------------------------------------------------------

    The Order envisages a complete restructuring of the natural gas 
industry. It may well come to rank with the three great regulatory 
milestones of the industry.* * *

[[Page 12292]]

    At stake is the role of interstate natural gas pipelines. 
Although they are obviously transporters of gas, they have until 
recently operated primarily as gas merchants. They buy gas from 
producers at the wellhead and resell it, mainly to local 
distribution companies (``LDCs'') but also to relatively large end 
users. The Commission has concluded that a prevailing pipeline 
practice--particularly their general refusal to transport gas for 
third parties where to do so would displace their own sales--has 
caused serious market distortions. It has found this practice 
``unduly discriminatory'' within the meaning of Sec. 5 of the NGA. 
Order 436 is its response.
    The essence of Order No. 436 is a tendency, in the industry 
metaphor, to ``unbundle'' the pipelines' transportation and merchant 
roles. If it is effective, the pipelines will transport the gas with 
which their own sales compete; competition from other gas sellers 
(producers or traders) will give consumers the benefit of a 
competitive wellhead market. [\78\]

    \78\ 824 F.2d at 993-94.
---------------------------------------------------------------------------

Indeed, since Order No. 436 issued, virtually all jurisdictional 
natural gas pipelines became ``open access'' transporters of natural 
gas.
    In analyzing the Commission's authority to remedy undue 
discrimination, the court never made the distinctions now being put 
forth by Union Electric and Carolina P&L. Rather, the court 
specifically focused on the Commission's authority under section 5 of 
the NGA and upheld the Commission's authority to remedy undue 
discrimination in the transportation of natural gas by requiring 
pipelines transporting natural gas to do so on a non-discriminatory 
basis.\79\ Similarly, the Commission in Order No. 888 found undue 
discrimination in the transmission of electric energy and required, 
pursuant to section 206 of the FPA (the FPA provision that parallels 
section 5 of the NGA), that if public utilities transmit electric 
energy in interstate commerce, they must do so on a non-discriminatory 
basis (i.e., offer non-discriminatory open access transmission).
---------------------------------------------------------------------------

    \79\ For example, as the AGD court explained with regard to its 
discussion of Maryland People's Counsel v. FERC, 761 F.2d 780 (D.C. 
Cir. 1985), ``we made it clear that blanket-certificate 
transportation, unconstrained by any nondiscriminatory access 
provision, might well require remedial action under Sec. 5.'' 824 
F.2d at 1000.
---------------------------------------------------------------------------

    Moreover, while the Commission may have imposed a ``condition'' on 
pipelines obtaining blanket certificates or providing section 311 
transportation in Order No. 436, this does not detract from the court's 
core finding in AGD that the Commission had the authority under section 
5 of the NGA to remedy undue discrimination by requiring open access 
transportation.\80\ The Commission chose in Order No. 436 to impose its 
open access remedy as a condition to pipelines obtaining a blanket 
certificate to transport natural gas, but its authority was rooted in 
the undue discrimination provisions of section 5. Additionally, the 
practical result of the conditioning was that all jurisdictional 
pipelines would have to provide open access transportation, a result 
that was clearly anticipated by the AGD court.\81\ Thus, there is no 
distinction in the result intended, or the result achieved, in either 
industry; in both cases, the intent was to remedy undue discrimination 
pursuant to the statutes governing each industry, and in both cases the 
result was that all transporters/transmitters must agree to open access 
non-discriminatory services if they seek to continue owning, 
controlling or operating monopoly interstate transportation facilities.
---------------------------------------------------------------------------

    \80\ We disagree with Union Electric that anything in the 
Commission's brief to the Supreme Court, opposing certiorari of AGD, 
contradicts our conclusion. We recognize, as the Commission 
explained in that brief, that there is no equivalent to section 7 of 
the NGA in the FPA. While this puts Order No. 888 on a somewhat 
different factual basis from AGD, it has no material effect on 
whether we have the authority to remedy undue discrimination by 
requiring non-discriminatory open access transmission.
    \81\ See 824 F.2d at 993-94 (``The Order envisages a complete 
restructuring of the natural gas industry. It may well come to rank 
with the three great regulatory milestones of the industry. * * 
*'').
---------------------------------------------------------------------------

Legislative History Behind the FPA and EPAct Does Not Preclude Our 
Action

    We disagree with the arguments that the legislative history behind 
Part II of the FPA establishes that the Commission cannot under any 
circumstance order wheeling under FPA sections 205 and 206.<SUP>82 We 
examined the legislative history of sections 205 and 206 at length in 
the NOPR and Order No. 888 and concluded that it supports our authority 
to order open access transmission as a remedy for undue 
discrimination.<SUP>83 We also have examined the legislative history of 
the EPAct amendments to sections 211 and 212 and conclude that Congress 
in EPAct did not resolve the issue of our authority under sections 205 
and 206 and left untouched whatever pre-existing authorities we had 
under these sections. The parties have raised nothing new on rehearing 
to persuade us that our interpretation is wrong. However, there are 
several arguments that we believe warrant further discussion.
---------------------------------------------------------------------------

    \82\ Parties have raised the legislative history of sections 205 
and 206, as well as the legislative history of the EPAct amendments 
to sections 211 and 212.
    \83\ FERC Stats. & Regs. at 31,676-78; mimeo at 120-27. Notice 
of Proposed Rulemaking and Supplemental Notice of Proposed 
Rulemaking, FERC Stats. & Regs. para. 32,514 at 33,053-56 (1995). 
Union Electric points to a statement in the Commission's 1987 brief 
to the U.S. Supreme Court, opposing certiorari of the AGD case; in 
that brief the Commission pointed out that the Supreme Court had 
noted, in Otter Tail, that the legislative histories of the FPA and 
NGA are ``materially different.'' As we explained in Order No. 888, 
we have thoroughly reexamined the legislative histories of the NGA 
and FPA with respect to this issue and now conclude that there is no 
material difference as to this issue in the legislative histories of 
the two statutes. Further, such a difference, whether or not it 
exists, was not crucial to the fundamental holdings of the AGD court 
and does not preclude that decision from applying equally in the 
electric industry. See FERC Stats. & Regs. at 31,676-78; mimeo at 
121-26. We also note that in its brief to the Supreme Court the 
Commission explicitly stated that neither Otter Tail nor any of the 
other electric cases cited ``presented the question whether the 
Commission could order wheeling to remedy undue discrimination or 
anticompetitive behavior. * * *'' FERC Brief at 25 (footnote 
omitted).
---------------------------------------------------------------------------

    Parties on rehearing argue that the existence of sections 211 and 
212 limit the Commission's wheeling authority and, in effect, remove 
our authority under section 206 to order any transmission as a remedy 
for undue discrimination.<SUP>84 We disagree. In enacting EPAct, 
Congress did not resolve the extent of our wheeling authority outside 
the context of sections 211 and 212.<SUP>85 As we explained above, 
while Congress in 1978 gave the Commission certain case-by-case 
authority to order transmission access, it also specifically provided 
in section 212(e) of the FPA that the case-by-case authorities were not 
to be construed as limiting or impairing any authority of the 
Commission under any other provision of law. Congress retained a 
similar savings clause when it amended sections 211 and 212 in 1992. 
Moreover, the legislative history of EPAct shows that when Congress 
amended sections 211 and 212, it was well aware of arguments regarding 
the scope of the Commission's remedial authority under section 
206.<SUP>86 Whereas Congress added an amendment prohibiting the 
Commission from ordering direct retail wheeling under any provision of 
the FPA, it chose not to add a prohibition on the Commission ordering 
wholesale wheeling as a remedy for undue

[[Page 12293]]

discrimination under sections 205 and 206.<SUP>87
---------------------------------------------------------------------------

    \84\ See discussion supra concerning AGD court's understanding 
that Order No. 436 was not a simple order that relied on voluntary 
actions of affected pipelines.
    \85\ Contrary to certain assertions, in Order No. 888 we viewed 
the statute as a whole and determined that section 211 in no way 
limited the broad authority Congress gave us to eradicate undue 
discrimination in the electric power industry.
    \86\ See note 71 and related discussion, supra.
    \87\ In response to Carolina P&L's argument that Congress gave 
the Commission a specific remedy under section 211 and the 
Commission should not presume that it has additional remedies in 
such a circumstance, we do not believe that section 211 can credibly 
be viewed either as a partial substitute for, or as superseding, the 
sections 205-206 undue discrimination remedial authority that is 
fundamental to the Federal Power Act. Indeed, section 211 is not 
written in terms of providing remedial authority to address undue 
discrimination but rather provides for case-by-case transmission 
service on request if the service is in the public interest and 
meets the other criteria in sections 211 and 212.
---------------------------------------------------------------------------

    We are not persuaded that this conclusion is wrong based on 
rehearing arguments that we ignored other legislative history of EPAct. 
Carolina P&L argues that we ignored various statements of Senator 
Wallop following the enactment of EPAct, which it alleges are counter 
to our claim of authority to order open access transmission as a remedy 
for undue discrimination. The utility is simply in error that we 
ignored these statements. We explicitly mentioned Senator Wallop's 
statements in Order No. 888 and gave our rationale for why section 211 
does not limit our authority to remedy undue discrimination.<SUP>88 
However, we believe it is important to elaborate on the context in 
which those statements were made and our interpretation of those 
statements.
---------------------------------------------------------------------------

    \88\ FERC Stat. & Regs. at 31,686-87; mimeo at 148-51.
---------------------------------------------------------------------------

    The primary focus of Senator Wallop's statements is on the 
transmission authority given by the EPAct amendments to sections 211 
and 212. These statements emphasize restrictions on our section 211 
wheeling authority, including the fact that section 211 does not give 
the Commission authority to order transmission access on its own motion 
or to order open access transmission.<SUP>89 We do not quarrel with 
these statements because sections 211 and 212 clearly do place 
restrictions on our authority to order access under those provisions. 
The statements also discuss the differences between the House 
introduced amendments to sections 211 and 212 (which would have 
provided broader and in some instances mandatory access authority) and 
the amendments that finally passed (which were more limited). We also 
do not disagree that changes were made to the bill that originally was 
introduced. At issue here, however, is not whether there are 
restrictions on our section 211 authority, but rather whether we have 
authority outside the context of section 211 to order transmission as a 
remedy for undue discrimination. The only statement among Senator 
Wallop's remarks that addresses this specific issue is one in which he 
says, ``In my opinion, neither the amendments made by this Act nor 
existing law give the FERC any authority to mandate open access 
transmission tariffs for electrical utilities.'' (emphasis added). We 
do not view one senator's opinion as in any way dispositive of the 
issue. As discussed supra, when Congress enacted the 1992 section 211 
amendments it was well aware of the outstanding legal issue of the 
Commission's authority to order access as a remedy for undue 
discrimination under section 206. It chose not to clarify this issue by 
prohibiting the Commission from ordering access, but instead retained 
the savings clause in section 212(e).
---------------------------------------------------------------------------

    \89\ Most of the statements talk in terms of ``The Conference 
Report provides. . . .'' and thus are referring only to the section 
211 and 212 provisions. See, e.g., 138 Cong. Rec. 517616 (Oct. 8, 
1992).
---------------------------------------------------------------------------

    The issue of our legal authority thus turns on the undue 
discrimination authority given to us in 1935, and the legislative 
history of sections 205 and 206. We discussed this at length in Order 
No. 888.<SUP>90 On rehearing, several entities emphasize the Otter Tail 
case and the legislative history referred to in that case. In 
particular, Union Electric recites Justice Stewart's discussion of the 
legislative history in his partial dissent in Otter Tail. We do not 
interpret that discussion to suggest that we do not have the authority 
to remedy undue discrimination by requiring open access transmission 
under any circumstance. As we explained in Order No. 888:

    \90\ FERC Stats. & Regs. at 31,676-78; mimeo at 120-27.
---------------------------------------------------------------------------

    In the FPA, while Congress elected not to impose common carrier 
status on the electric power industry, it tempered that 
determination by explicitly providing the Commission with the 
authority to eradicate undue discrimination--one of the goals of 
common carriage regulation. By providing this broad authority to the 
Commission, it assured itself that in preserving ``the voluntary 
action of the utilities'' it was not allowing this voluntary action 
to be unfettered. It would be far-reaching indeed to conclude that 
Otter Tail, which was a civil antitrust suit that raised issues 
entirely unrelated to our authority under section 206, is an 
impediment to achieving one of the primary goals of the FPA--
eradicating undue discrimination in transmission in interstate 
commerce in the electric power industry. [<SUP>91]
---------------------------------------------------------------------------

    \91\ FERC Stats. & Regs. at 31,670; mimeo at 103.

    In response to Union Electric's arguments that Congress explicitly 
rejected common carrier provisions in 1935, we do not disagree with 
Union Electric's statement that ``the mandatory wheeling language was 
not dropped inadvertently.'' <SUP>92 The point that we made in Order 
---------------------------------------------------------------------------
No. 888 (quoting AGD) in this regard was that

    \92\ Union Electric at 26.
---------------------------------------------------------------------------

    (1) ``Congress declined itself to impose common carrier status'' 
(emphasis added) and (2) there is no ``support for the idea that the 
Commission could under no circumstances whatsoever impose 
obligations encompassing the core of a common carriage duty.'' 
[<SUP>93]

    \93\ FERC Stats. & Regs. at 31,677; mimeo at 122.
---------------------------------------------------------------------------

Nowhere did we ever suggest that the mandatory wheeling language was 
dropped inadvertently; we simply distinguish a general common carrier 
obligation imposed ``in the public interest'' from an obligation to 
provide transmission service deemed necessary to eliminate undue 
discrimination. Finally, we fully agree with Union Electric's statement 
that

[a]lthough this ``first Federal effort'' occurred in 1935, the 
resulting FPA Sections 205 and 206 have not been modified in any 
relevant respect since that time. Therefore, the range of authority 
conveyed to the Commission in such sections remains the same today 
as it did then. [<SUP>94]

    \94\ Union Electric at 27.
---------------------------------------------------------------------------

We never suggested otherwise and our conclusion in Order No. 888 is not 
based on a finding to the contrary.

Case Law Does Not Prohibit Our Ordering Wheeling Under Sections 205 
and 206 of the FPA

    Union Electric, discussing the very cases cited by the Commission 
in Order No. 888, asserts that ``the Commission fails to recognize 
their dispositive results prohibiting it from ordering wheeling under 
the Sections 205 and 206 of the FPA.'' <SUP>95 We thoroughly examined 
all of the case law cited by Union Electric, as evidenced by our 
discussions in the NOPR and Order No. 888, and disagree that any of 
those cases prohibit the Commission from ordering wheeling under 
sections 205 and 206 of the FPA to remedy undue discrimination. Indeed, 
the AGD court reached the same conclusion.<SUP>96
---------------------------------------------------------------------------

    \95\ Union Electric at 30.
    \96\ The only relevant case the AGD court did not discuss was 
NYSEG. As we explained in Order No. 888, presumably this was because 
the case did not concern whether the Commission could order wheeling 
as a remedy for undue discrimination. FERC Stats. & Regs. at 31,672 
n.217; mimeo at 108 n.217.
---------------------------------------------------------------------------

    Union Electric further cites to a variety of FPC cases that it 
claims demonstrate that the Final Rule exceeds the Commission's 
statutory authority.<SUP>97 It appears to have proffered every negative 
Commission statement it could find with respect to our authority to 
order wheeling under Part II of the FPA.

[[Page 12294]]

As in the Commission cases cited, we recognize that our authority to 
order transmission service is not unbounded; if we order transmission, 
it must be within the scope of authority available to us under the FPA. 
However, the fact is that none of the cases cited as establishing 
limits on the Commission's authority addresses the issue before us now, 
i.e., the Commission's authority to order transmission as a remedy for 
undue discrimination. Simply stated, the Commission has never before 
been faced with generic findings of undue discrimination in the 
provision of interstate electric transmission services, and the extent 
of its authority to remedy that undue discrimination.
---------------------------------------------------------------------------

    \97\ Union Electric at 33-37.
---------------------------------------------------------------------------

The Commission's General Counsel Never Asserted, or Even Suggested, 
That the Commission Does Not Have the Authority to Order Wheeling 
as a Remedy for Undue Discrimination

    Union Electric spends several pages of its rehearing request 
asserting that the Commission's own General Counsel has acknowledged 
the limitations on the Commission's authority to order wheeling. 
<SUP>98 In particular, it points to a statement by a Commission OGC 
witness that ``if Congress intends for the Commission to be able to 
deal with transmission on its own motion and thereby go further than 
simply dealing with industry proposals,'' Congress would need ``to 
include an affirmative statement somewhere in the Act that the 
Commission could require wheeling on its own motion.'' <SUP>99 This 
same statement was previously raised by EEI and previously addressed in 
Order No. 888. We do not disagree that this statement was made. 
However, it must be read in the context of the witness' entire 
testimony in which the witness stated four times the view that the case 
law supports the argument that the Commission has authority to order 
wheeling as a remedy for undue discrimination.<SUP>100 Indeed, contrary 
to Union Electric's assertion, the extensive legal analysis set forth 
by the Commission's witness supports the position relied upon in this 
proceeding.<SUP>101 Thus, viewed in the context of the witness' entire 
testimony, Union Electric's arguments to the contrary are unavailing. 
Moreover, nowhere did the witness ever suggest, as asserted by Union 
Electric, that FPA sections 205 and 206 could only be used ``to 
eliminate unduly discriminatory terms in a wheeling arrangement 
voluntarily filed with the Commission.'' <SUP>102
---------------------------------------------------------------------------

    \98\ Union Electric at 37-40.
    \99\ Union Electric at 38-39.
    \100\ Hearings on H.R. 1301, H.R. 1543, and H.R. 2224 before the 
Subcommittee on Energy and Power of the House Committee on Energy 
and Commerce, 102d Cong., 1st Sess. (May 1, 2 and June 26, 1991), 
Statement of Cynthia A. Marlette, Associate General Counsel, Federal 
Energy Regulatory Commission, Report No. 102-60 at 60 (``However, as 
discussed below, there are strong legal arguments that the 
Commission's obligation to protect against undue discrimination 
carries with it the authority to impose transmission requirements as 
a remedy for undue preference or discrimination.'' ``As discussed 
below, although the case law in this area has been uncertain, in 
OGC's opinion there is a strong legal argument that the Commission 
can require transmission as a remedy for undue preference or undue 
discrimination.''); at 69-70 (``The weight of the limited case law, 
particularly the AGD opinion, supports authority to order wheeling 
as a remedy for undue discrimination where substantial evidence 
exists.''); at 106 (``I believe that we have substantial authority 
under the existing case law to mandate access where necessary to 
remedy anticompetitive effects.'').
    \101\ The statement quoted was preceded by a legal analysis of 
the Commission's authorities under then existing law, including 
section 206, and a statement that an examination of the Commission's 
full authorities might further open up the industry. Further, it was 
made in the context of case-by-case industry proposals and the 
Commission's inability to require case-by-case wheeling on its own 
motion. It did not address section 206 authority to remedy undue 
discrimination.
    \102\ Union Electric at 39. We note that Union Electric did not 
cite to any page or particular language to support its assertion.
---------------------------------------------------------------------------

The Commission Has the Authority to Order Public Utilities to Make 
Rate Filings in This Proceeding

    We reject Union Electric's argument that our requirement that Group 
2 Public Utilities make section 205 filings is contrary to the 
voluntary filing scheme inherent in section 205. It is true that the 
Commission ordinarily cannot require a utility to make a section 205 
filing. However, in this situation the section 205 filing was required 
as a remedy under section 206 of the FPA to establish rates for non-
discriminatory open access transmission. Acting pursuant to section 206 
of the FPA, we found that undue discrimination exists in the wholesale 
transmission of electric power and ordered the filing of non-
discriminatory open access transmission tariffs to remedy this 
discrimination. Section 206 further requires that upon such a finding 
the Commission ``shall determine the just and reasonable rate, charge, 
classification, rule, regulation, practice, or contract to be 
thereafter observed and in force. * * *'' Thus, we had the authority to 
set the rates that would be observed and in force following the 
effectiveness of open access transmission and initially proposed to set 
rates for each public utility. However, rather than take this intrusive 
approach, which necessarily would have required a number of generic 
assumptions and resulted in less than public utility-specific rates, 
upon issuance of the Final Rule, we chose to permit these public 
utilities to make section 205 filings to propose their own rates for 
the services provided in the pro forma tariff.

The Commission's Prior Failure to Order Wheeling as a Remedy for 
Undue Discrimination Is Not Dispositive

    After discussing several cases that it asserts address the 
Commission's authority to remedy undue discrimination, Carolina P&L 
declares that ``[p]erhaps the strongest evidence that the Commission 
lacks the power to compel wheeling under FPA section 206 is the fact 
that the Commission has never previously exercised this alleged power, 
despite numerous opportunities to do so.'' <SUP>103 However, the court 
in AGD succinctly dismissed a similar argument:

    \103\ Carolina P&L at 35-36.
---------------------------------------------------------------------------

    It is finally argued that the Commission's not having imposed 
any requirements like those of Order No. 436 in the period from 
enactment in 1938 until the present demonstrates the lack of any 
power to do so. * * * But as our introductory review of the economic 
background sought to illustrate, the Commission here deals with 
conditions that are altogether new. Thus no inference may be drawn 
from prior non-use. [<SUP>104]
---------------------------------------------------------------------------

    \104\ 824 F.2d at 1001. In this regard, we acknowledge that our 
view of what constitutes undue discrimination has evolved 
significantly in light of the dramatic economic changes in the 
industry, as described briefly above and more fully in Order No. 
888.
---------------------------------------------------------------------------

Undue Discrimination/Anticompetitive Effects <SUP>105
---------------------------------------------------------------------------

    \105\ FERC Stats. & Regs. at 31,682-84; mimeo at 136-42.
---------------------------------------------------------------------------

    A number of utilities and state commissions argue that the 
Commission lacks evidence to support a finding of undue 
discrimination.<SUP>106
---------------------------------------------------------------------------

    \106\ E.g., El Paso, Union Electric, Carolina P&L, VA Com, FL 
Com, PA Com.
---------------------------------------------------------------------------

    VA Com argues that the Commission failed to make a legally 
supportable finding of industry-wide undue discrimination: ``FERC 
apparently drew a conclusion that there was undue discrimination in the 
NOPR without support and later accepted customers' allegations, without 
further inquiry, and relied on them in making its finding of industry-
wide undue discrimination.'' (VA Com at 2-3).
    PA Com and Carolina P&L assert that allegations of undue 
discrimination do not form a sufficient basis to compel a generic 
rulemaking. Not coming forward with specific accusations and the 
identity of specific accusers, PA Com asserts, is unconstitutional as a 
deprivation of due process.

[[Page 12295]]

    With regard to specific allegations of undue discrimination, SoCal 
Edison argues that the Commission inappropriately relied upon 
allegations involving SoCal Edison as evidence of undue discrimination. 
SoCal Edison asks that the Commission declare that it is not making a 
factual determination as to any particular allegation especially since 
prior to 1994 the Commission defined discrimination differently. Dalton 
similarly argues that the Commission has no basis for finding that 
Georgia Power Company is engaged in unlawful undue discrimination as to 
new or roll-over transmission services in the operation of the 
Integrated Transmission System in Georgia (ITS) under the ITS 
agreement. Moreover, Dalton argues, even if it is found that GPC acted 
in unduly discriminatory manner, it is not practical or lawful to order 
open access tariff for new and roll-over services.
    Finally, Carolina P&L argues that the comparability standard does 
not eliminate the ``requirement'' that parties must be similarly 
situated before discrimination is present, and that the Commission has 
not provided factual support for its implicit finding that public 
utilities and their native load customers are similarly situated to 
third parties. It cites City of Vernon v. FERC, 845 F.2d 1042 at 1045-
46 (D.C. Cir. 1988), in support.

Commission Conclusion

    As an initial matter, the Commission grants SoCal Edison's request 
for clarification that in Order No. 888 we did not make a factual 
determination as to any particular allegation of past discrimination 
described in the Final Rule.<SUP>107 However, we reject arguments that 
the Commission cannot rely in part on the array of allegations and 
circumstances raised by customers in individual cases over the years 
and brought forth in response to the NOPR. The specific allegations are 
illustrative. However, they present examples of the types of 
discriminatory incentives and behavior inherent in ownership of 
monopoly transmission facilities, and also present credible examples of 
the types of discriminatory behavior in which public utilities could 
engage in the future. We also reject arguments that customers and the 
Commission must litigate and make specific findings of discrimination 
against each public utility before we can take any action to preclude 
discriminatory behavior that will harm competition and, ultimately, 
electricity consumers. This is particularly true where the 
discriminatory behavior clearly is in the economic self-interest of a 
monopoly transmission owner facing the markedly increased competitive 
pressures that are driving today's electric utility industry. As we 
recognized in Order No. 888,

    \107\ In response to PA Com's and Carolina P&L's assertions that 
not coming forward with specific accusations and identities of 
specific accusers is unconstitutional and a deprivation of due 
process, we emphasize that the Commission has not denied due process 
to anyone. The Final Rule does not, nor is it intended to, make 
specific findings as to any particular utility or any particular 
allegation raised.
---------------------------------------------------------------------------

[t]he inherent characteristics of monopolists make it inevitable 
that they will act in their own self-interest to the detriment of 
others by refusing transmission and/or providing inferior 
transmission to competitors in the bulk power markets to favor their 
own generation, and it is our duty to eradicate unduly 
discriminatory practices. As the AGD court stated: ``Agencies do not 
need to conduct experiments in order to rely on the prediction that 
an unsupported stone will fall.'' <SUP>108

    \108\ FERC Stats. & Regs. at 331,682; mimeo at 136-37.
---------------------------------------------------------------------------

    We believe that the same general discriminatory circumstances that 
faced us when we required open access transportation in the natural gas 
industry <SUP>109 are also before us today in the electric industry. 
First, it is uncontested that market power continues to exist in the 
ownership and operation of the monopoly-owned facilities that comprise 
the nation's interstate transmission grid. Second, utilities, as a 
general matter, did not in the past offer comparable transmission 
services to competitors or to customers. Open access services simply 
were not made available by utilities until the late 1980s when the 
Commission began to impose open access as a condition of approval of 
market-based rates and utility mergers in order to mitigate market 
power and remedy anticompetitive effects. Rather, the vast majority of 
utilities historically have declined to transport electric energy that 
would compete with their own sales or have offered access that is 
inferior to what they use for their own sales. Third, discrimination in 
transmission services, when viewed in light of utilities' own uses of 
their transmission systems compared to what they offer third parties, 
has denied and will continue to deny customers access to electricity at 
the lowest reasonable rates. The entities on rehearing have raised 
nothing to persuade us that it is in the interests of consumers to 
maintain the self-evident incentives for transmission owners to 
exercise their monopoly power over transmission to discriminate in 
favor of their own generation sales--incentives that will only increase 
in the future as competitive pressures continue to escalate.
---------------------------------------------------------------------------

    \109\ See AGD, 824 F.2d at 999-1000.
---------------------------------------------------------------------------

    The Commission addressed the same argument as that being made by 
Carolina P&L, that the Commission has not made the requisite finding 
that third-party transmission customers are similarly situated to 
public utilities and their native load customers, in 1994 in the NEPOOL 
and AEP cases.<SUP>110 In these cases, we recognized that the 
traditional focus of our undue discrimination analysis had been whether 
factual differences justify different rates, terms and conditions for 
similarly situated customers, but concluded that due to changing 
conditions in the electric utility industry, it was necessary to 
reevaluate our traditional analysis. As we stated in NEPOOL, the focal 
point of undue discrimination claims has shifted from claims of undue 
discrimination in rates and services which the utility offers different 
customers to claims of undue discrimination in rates and services which 
the utility offers when compared to its own use of the transmission 
system.<SUP>111 ``In this context, framing the analysis in terms of how 
a public utility treats similarly situated customers is not applicable 
or instructive.'' <SUP>112 The Commission concluded that it therefore 
must reexamine its application of the standard for undue discrimination 
claims under sections 205 and 206 of the FPA.
---------------------------------------------------------------------------

    \110\ New England Power Pool, 67 FERC para. 61,402 (1994) 
(NEPOOL); American Electric Power Service Corporation, 64 FERC para. 
61,279 (1993), reh'g granted, 67 FERC para. 61,168, clarified, 67 
FERC para. 61,317 (1994) (AEP).
    \111\ 67 FERC para. 61,042 at 61,132.
    \112\ Id.
---------------------------------------------------------------------------

    The Commission further elaborated on its re-examination of undue 
discrimination in AEP. The Commission cited its NEPOOL discussion and 
set for hearing the different uses that AEP made of its transmission 
system and whether there were any operational differences between any 
particular use that AEP made of the system and the use third parties 
might need, and, in particular, the degree of flexibility AEP accorded 
itself in using its transmission system for different purposes. The 
Commission subsequently set the same issue for hearing in several other 
cases.<SUP>113 In the NOPR, however, the Commission concluded that 
based on what it had learned in the ongoing cases, it would address 
this issue generically in this rulemaking. We announced in the NOPR our 
belief that

[[Page 12296]]

all utilities use their own systems in two basic ways: to provide 
themselves point-to-point transmission service that supports 
coordination sales, and to provide themselves network transmission 
service that supports the economic dispatch of their own generation 
units and purchased power resources (integrating their resources to 
meet their internal load). Third parties may need one or both of these 
basic uses in order to obtain competitively priced generation or to 
have the opportunity to be competitive sellers of power, and the 
Commission proposed that all public utilities must offer both services 
on a non-discriminatory open access basis.<SUP>114
---------------------------------------------------------------------------

    \113\ Commonwealth Edison Co., 70 FERC para. 61,204 (1995); 
Wisconsin Electric Power Co., 70 FERC para. 61,074 (1995); and 
Wisconsin Public Service Corp., 70 FERC para. 61,075 (1995) 
    \114\ FERC Stats. & Regs. para. 32,524 at 33,079.
---------------------------------------------------------------------------

    We affirmed this determination in the Final Rule. We concluded that 
a public utility must offer transmission services that it is reasonably 
capable of providing, not just those services that it is currently 
providing to itself or others. Because a public utility that is 
reasonably capable of providing transmission services may provide 
itself such services at any time it finds those services desirable, it 
is irrelevant that it may not be using or providing that service 
today.<SUP>115 Thus, based on the analysis in this record, the 
Commission has determined that undue discrimination in the provision of 
transmission services in today's industry does not turn on whether 
utilities and their native load customers are similarly situated to 
third parties, but instead turns on whether the utility is providing 
comparable service, that is, service that it is reasonably capable of 
providing to other users of the interstate transmission system.
---------------------------------------------------------------------------

    \115\ FERC Stats. & Regs. at 31,690; mimeo at 160.
---------------------------------------------------------------------------

    In short, the Commission is not bound to a static application of 
its undue discrimination analysis under the FPA and, indeed, has a 
public interest responsibility to reexamine undue discrimination in 
light of changed circumstances in the industry.<SUP>116 That is what we 
began in NEPOOL and AEP and have completed in this rulemaking. The 
traditional ``similarly situated'' test, while applicable to 
discrimination among third-party customers, simply is not applicable 
when analyzing discrimination between third-party transmission 
customers and transmission owners. Under Carolina P&L's theory, 
presumably the only customers that could be shown to be similarly 
situated would be those who own monopoly transmission facilities and 
have native load (i.e., captive) customers. This would preserve 
customer captivity, perpetuate monopoly power and profits, and deny the 
lowest reasonable rates to consumers. We therefore reject Carolina 
P&L's arguments.
---------------------------------------------------------------------------

    \116\ There is no ``requirement'' in the FPA that the Commission 
apply a ``similarly situated'' test. Carolina P&L's reliance on City 
of Vernon is misplaced. That case involved a claim of discrimination 
in the type of service offered to a wholesale customer versus that 
offered to retail customers, and the Commission's application of the 
``similarly situated'' and ``same service'' test. Contrary to 
Carolina P&L's implication, the case does not hold that the 
Commission is bound to apply a ``similarly situated'' test in 
analyzing undue discrimination claims under the FPA.
---------------------------------------------------------------------------

    Moreover, the fact that public utilities and their native load 
customers have been treated differently from third-party transmission 
customers because they are not among those traditionally considered to 
be ``similarly situated'' is precisely the target at which Order No. 
888 takes aim. Historically, competitively-priced power was not broadly 
available to wholesale customers because the industry was dominated by 
vertically integrated IOUs <SUP>117 and, to the extent cheaper 
generation alternatives were available in the marketplace, transmission 
owners either took the cheaper power for their own uses or purchased 
and re-sold it at a profit.<SUP>118 Prior to EPAct, most power 
customers took power from the vertically integrated utilities that 
provided their transmission service. Transmission-only transactions 
played a secondary role in bulk power markets, facilitating certain 
economy transactions and coordination and pooling arrangements that 
improved utility operational efficiencies, largely as a complement to 
bundled bulk power transactions. Given the predominantly vertically-
integrated industry and efficiencies that could be gained through 
encouragement of coordination and pooling transactions, the Commission 
was willing to accept utility practices that provided third parties 
with transmission services that were distinctly inferior to the 
utility's own uses of the transmission system.
---------------------------------------------------------------------------

    \117\ I.e., investor-owned utilities that owned generation, 
transmission and distribution facilities and most of whom had 
captive customers.
    \118\ Very simply, the transmission owner was able to prevent 
third parties from achieving the maximum savings possible in the 
generation market by withholding or delaying transmission service. 
Alternatively, the transmission owner could purchase the power and 
resell it to the third party at a rate that reflected a mark-up from 
the first power sale.
---------------------------------------------------------------------------

    In the future, however, unbundled transmission service will be the 
centerpiece of a freely traded commodity market in electricity, in 
which all wholesale customers can shop for power. In a market 
characterized by a significant increase in non-vertically integrated 
power suppliers and competitively priced power that is now meaningfully 
available, it is no longer in the interest of wholesale customers for 
the Commission to tolerate the types of practices that were previously 
accepted. We cannot allow what have become unduly discriminatory 
practices to erect barriers between customers and the rapidly emerging 
competitive electricity marketplace. Accordingly, a primary goal of 
Order No. 888 is to provide that in the future transmission providers 
and third-party transmission customers are ``similarly situated'' in 
the quality of transmission service available to them.

C. Comparability

1. Eligibility to Receive Non-discriminatory Open Access Transmission
    In the Final Rule, the Commission modified the definition of 
``eligible customer'' and, among other things, clarified that any 
entity engaged in wholesale purchases or sales of electric energy, not 
just those ``generating'' electric power, is eligible.<SUP>119 The 
Commission also clarified that entities that would violate section 
212(h) of the FPA (prohibition on Commission-mandated wheeling directly 
to an ultimate consumer and sham wholesale transactions) are not 
eligible. Further, the Commission clarified that foreign entities that 
otherwise meet the eligibility criteria may obtain transmission 
services. The Commission also provided for service to retail customers 
in circumstances that do not violate FPA section 212(h). Persons that 
would be eligible section 211 applicants also would be eligible under 
the open access tariff.
---------------------------------------------------------------------------

    \119\ FERC Stats. & Regs. at 31,688-90; mimeo at 154-58.
---------------------------------------------------------------------------

a. Unbundled Retail Transmission and ``Sham Wholesale Transactions''

Rehearing Requests

    Several entities assert that there is an inconsistency between 
tariff language and preamble language and argue that section 1.11 of 
the tariff should be made consistent with the preamble to ensure that, 
absent a state-approved program, retail wheeling is not available under 
the tariff, no matter which party requests service.<SUP>120 They 
maintain that the limitation in section 1.11 that the transmission 
provider only must provide retail transmission service voluntarily or 
under a state-approved program appears to apply only when a retail 
customer is the purchaser, not when the transmission purchaser is an 
electric utility. They suggest the

[[Page 12297]]

following language to remedy the problem: ``however, such entity is not 
eligible for transmission service that would be prohibited by Sections 
212(h)(1) and/or 212(h)(2) of the Federal Power Act, unless such 
service is provided pursuant to a state retail access program or 
pursuant to a voluntary offer of unbundled retail transmission service 
by the Transmission Provider.'' (PSE&G at 22; Carolina P&L at 8-9).
---------------------------------------------------------------------------

    \120\ E.g., SoCal Edison, PSE&G, Carolina P&L.
---------------------------------------------------------------------------

    Detroit Edison argues that the Commission should modify the 
definition to exclude any reference to transmission service provided to 
retail customers so as to avoid confusion and possible forum shopping. 
At the least, Detroit Edison argues, the Commission should modify the 
language to state that transmission service is available to an ultimate 
consumer to the extent, and only to the extent, that the service is 
authorized by a lawful state retail access program or pursuant to a 
voluntary offer of unbundled retail transmission service by the 
transmission provider.
    NYSEG asserts that the Commission did not apply the section 212(h) 
limitation to service to retail customers under the tariff. NYSEG 
requests that the Commission clarify that it will not require retail 
wheeling beyond the scope of state-mandated retail access programs or 
beyond the terms of a transmission provider's voluntary offer of retail 
wheeling service.
    Oklahoma G&E asks the Commission to clarify that the term eligible 
customer differentiates between a customer eligible to receive 
transmission service and a customer whose transaction is a sham or 
would result in mandatory retail wheeling and would therefore be 
prohibited by section 212(h).
    NYSEG further asserts that the right of first refusal provision 
would permit a retail customer receiving wheeling service to continue 
to take that service upon expiration of its contract, which could 
require the transmission provider, in violation of section 212(h), to 
continue retail wheeling beyond the scope of its voluntary offer of 
service or beyond the scope of a state-mandated retail access program.
    SoCal Edison argues that the Commission cannot compel a utility to 
supply retail transmission service if the utility challenges the 
authority of the state to require retail wheeling and section 1.11 
should be revised to reflect this.
    IL Com declares that it ``does not recognize FERC's claim of 
jurisdiction over retail transmission service provided directly to a 
retail customer and disputes that unbundled retail wheeling directly to 
a retail customer is a service provided in interstate commerce.'' (IL 
Com at 35). Thus, ``if FERC's proposed `deference' to states is to be 
given any effect, states must be allowed to determine whether the 
retail transmission component of the retail wheeling program will be 
provided pursuant to the utility's existing filed wholesale tariff or 
whether the retail transmission will be provided pursuant to a 
`separate retail transmission tariff' that is different from the 
wholesale tariff.'' (IL Com at 36). IL Com concludes that it is 
inappropriate (and illegal if FERC is overturned on its retail 
transmission jurisdiction assertion) to include retail customers taking 
final delivery of unbundled power for their own end uses under retail 
wheeling programs as eligible customers.
    PA Com argues that it is relevant whether a customer is receiving 
retail or wholesale service and redefining transmission and local 
distribution service does not automatically convey jurisdiction to the 
Commission.
    CCEM asks that the Commission clarify that a retail customer 
eligible to seek transmission service should be able to seek 
transmission service not only from the transmission provider, but from 
any other transmission provider. CCEM also asks that the Commission add 
the word ``ultimate'' before the word transmission provider in section 
1.11 of the tariff.
    EEI asks the Commission to ``clarify that the transmission service 
provider should be allowed to supplement the terms and conditions of 
the pro forma tariff with additional provisions that specifically 
relate to the totality of the transmission service being provided, 
including the use of distribution facilities and any other transmission 
facilities not currently included in wholesale rates.'' (EEI at 24 
(emphasis in original)).<SUP>121
---------------------------------------------------------------------------

    \121\ See also CSW Operating Companies.
---------------------------------------------------------------------------

    Union Electric argues that a literal reading of the eligibility 
definition could require retail wheeling by utilities in states other 
than those required to participate in a particular retail wheeling 
program.

Commission Conclusion

    The Commission agrees with those entities that argue that section 
1.11 of the pro forma tariff does not explicitly prohibit ``sham 
wholesale transactions'' that could currently be arranged under the 
tariff by a utility applying for service and designating the retail 
customer as a point of delivery. We therefore have modified section 
1.11 to clarify that, with respect to service that we are prohibited 
from ordering by section 212(h) of the FPA (whether direct retail 
wheeling or ``sham'' wholesale wheeling), otherwise eligible entities 
may obtain such service under the tariff only if it is pursuant to a 
state requirement that such service be provided or pursuant to a 
voluntary offer of such service. We also have modified the language to 
clarify that eligibility for unbundled direct retail service required 
by a state applies only to service from transmission providers that the 
state orders to provide the service. The modified language states:

    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.

    Regarding SoCal Edison's argument, the Commission stated in the 
Final Rule:

    Moreover, we are mindful of the fact that we are precluded under 
section 212(h) from ordering or conditioning an order on a 
requirement to provide wheeling directly to an ultimate consumer or 
sham wholesale wheeling. We therefore clarify that our decision to 
eliminate the wholesale customer eligibility requirement does not 
constitute a requirement that a utility provide retail transmission 
service. Rather, we make clear that if a utility chooses, or a state 
lawfully requires, unbundled retail transmission service, such 
service should occur under this tariff unless we specifically 
approve other terms.<SUP>[122]

    \122\ FERC Stats. & Regs. at 31,689-90; mimeo at 158.
---------------------------------------------------------------------------

    Therefore, the Commission is not compelling a utility to provide 
un-
bundled retail transmission service.<SUP>123 Rather, the Commission 
requires that

[[Page 12298]]

should such service be provided, either pursuant to state mandate or 
voluntarily, it must be provided pursuant to the pro forma tariff 
unless the Commission approves alternative terms and conditions.
---------------------------------------------------------------------------

    \123\ We also disagree with NYSEG's assertion that the right of 
first refusal provision would permit a retail customer receiving 
wheeling service to continue to receive service after the expiration 
of its contract and could require the transmission provider to 
continue wheeling beyond the scope of its voluntary offer of service 
or beyond the scope of a state-mandated retail access program. 
Section 212(h) of the FPA would override any provision, including 
the right of first refusal provision, that may be included in the 
pro forma tariff.
---------------------------------------------------------------------------

    However, in light of CCEM's request that we clarify that a retail 
customer eligible to seek transmission service under the tariff should 
be able to seek service not only from the transmission provider, but 
also from any other transmission provider, and in light of Union 
Electric's concerns regarding retail service eligibility, we believe 
certain clarifications of our jurisdiction and of the statements made 
in Order No. 888 are necessary. The statements cited above that were 
made in Order No. 888 and the eligible customer tariff definition in 
(ii) above refer to direct retail transmission, i.e., the transmission 
of electric energy ``directly'' to an ultimate consumer. The Commission 
is prohibited by section 212(h)(1) of the FPA from ordering this type 
of retail transmission and that is why customers are eligible for such 
transmission under the tariff only if the transmission is pursuant to a 
state order or is provided voluntarily. However, on its face, section 
212(h) does not prohibit the Commission from ordering public utilities 
to provide ``indirect'' unbundled retail transmission in interstate 
commerce, i.e., the transmission necessary to transmit unbundled 
electric energy to a utility that ultimately will deliver the energy to 
a customer that is purchasing the unbundled energy at retail either 
pursuant to a state retail access order or pursuant to voluntary 
delivery by the local utility.
    We clarify that we believe we have the jurisdiction under the FPA 
to order indirect retail transmission to an ultimate consumer and that 
if the Commission under sections 205, 206 or 211 of the FPA orders such 
transmission, entities that otherwise qualify as eligible customers 
under the tariff will take transmission service for such indirect 
retail wheeling pursuant to the pro forma tariff. We note that the 
Commission may order such transmission on a case-by-case basis or may 
determine to do so generically in the future. We expect public 
utilities to provide such indirect retail access under the pro forma 
tariff and, if they do not, we will not hesitate to order them to do 
so.
    In response to IL Com's argument that it does not recognize this 
Commission's claim of jurisdiction over the rates, terms and conditions 
of unbundled retail transmission that is provided directly to an 
ultimate consumer, the Commission reaffirms its legal conclusion set 
forth in the Final Rule.<SUP>124 As to its claim that we should give 
deference to the state as to whether such service could be taken under 
the wholesale tariff or a separate retail tariff on file with the 
Commission, we reaffirm our conclusion to address this on a case-by-
case basis. Since the Final Rule issued, the Commission has addressed 
this in several orders. In New England Power Company, the Commission 
stated: <SUP>125

    \124\ FERC Stats. & Regs. at 31,780 and Appendix G (31,966-81); 
mimeo at 428 and Appendix G.
    \125\ 75 FERC para. 61,356 at 62,141, order on reh'g, 77 FERC 
para. 61,135 (1996). In the order on rehearing, the Commission 
permitted a separate retail tariff to remain in effect for the 
duration of the retail electric pilot programs established in 
Massachusetts by Massachusetts Electric Company.

    As we explained in the Open Access Rule and in the New Hampshire 
Interim Order, we generally expect retail transmission customers to 
take service under the same Commission tariff that applies to 
wholesale customers. While we generally will defer to state requests 
for a separate retail tariff to accommodate the design and special 
needs of a state retail access program, the Massachusetts Commission 
---------------------------------------------------------------------------
has made no such request in this case. \15\

    \15\ See Open Access Rule, FERC Stats. & Regs. at 31,784; New 
Hampshire Interim Order, 75 FERC at 61,687 & n.3 (both noting that 
such a separate retail tariff must be consistent with the 
Commission's open access policies and comparability principles). * * 
*

    Subsequently, in New England Power Company, 76 FERC para. 61,008 
(1996), the Commission granted a limited waiver of the Open Access Rule 
requirements for the New Hampshire retail electric competition pilot 
project. Specifically, the Commission waived the requirement for 
individual service agreements, and the requirement for customer 
---------------------------------------------------------------------------
deposits. The Commission further announced that:

other public utilities that provide unbundled retail service under a 
pro forma tariff do not need to apply to retail customers the tariff 
provisions regarding individual service agreements or customer 
deposits, unless a state retail program so requires. [ <SUP>126]

    \126\ 76 FERC at 61,024.
---------------------------------------------------------------------------

    Concerning EEI's request for clarification, the Commission stated 
in the Final Rule:

all tariffs need not be ``cookie-cutter'' copies of the Final Rule 
tariff. Thus, under our new procedure, ultimately a tariff may go 
beyond the minimum elements in the Final Rule pro forma tariff or 
may account for regional, local, or system-specific factors. The 
tariffs that go into effect 60 days after publication of this Rule 
in the Federal Register will be identical to the Final Rule pro 
forma tariff; however, public utilities then will be free to file 
under section 205 to revise the tariffs, and customers will be free 
to pursue changes under section 206.<SUP>[127]

    \127\ FERC Stats. & Regs. at 31,770 n. 514; mimeo at 399 n. 514.
---------------------------------------------------------------------------

    Utilities are free to include customer-specific terms and 
conditions or terms and conditions limited to certain customers (e.g., 
a distribution charge) in the customer's service agreement and/or the 
network customer's network operating agreement.
b. Transmission Providers Taking Service Under Their Tariff

Rehearing Requests

    TAPS states that section 1.11 does not seem to require a 
transmission provider to take service for its purchases, but the 
preamble does (citing mimeo at 57, 191, 266 and regulatory text in 
section 35.28(c)(2)). It argues that transmission providers should be 
required to treat their own usage of the transmission system to serve 
retail customers under the network service provisions of the tariff. 
TAPS argues that this result could be achieved through an ISO or by 
requiring transmission providers to abide by all non-price terms of 
Parts I and III of the tariff. TAPS also argues that the rates charged 
network customers must be developed on the same basis as the 
transmission component of retail rates. It states that the transmission 
provider's purchases would then be made under Part III of the tariff to 
the extent they are made for serving retail customers. It further 
asserts that the Commission's authority and obligation to consider 
transmission owners' service to retail load in establishing wholesale 
transmission rates has been long established. At the least, TAPS argues 
that the Commission should require that a transmission provider take 
its wholesale purchases under some tariff.
    Similarly, Coalition for Economic Competition asks the Commission 
to clarify that the requirement to use the pro forma tariff for 
wholesale purchases and to functionally unbundle wholesale purchases 
and sales does not apply to purchases made solely to serve retail 
customers on a bundled basis. It asserts that there is conflicting 
language in Order No. 888 (citing mimeo at 191) and Order No. 889 
(citing mimeo at 12) and the pro forma tariff. Coalition for Economic 
Competition asserts that the Commission does not have jurisdiction over 
transmission that is part of a bundled retail sale.

[[Page 12299]]

Commission Conclusion

    Several parties have noted on rehearing that there is conflicting 
language among the Final Rule, Order No. 889 and the pro forma tariff 
as to whether and to what extent the transmission provider must take 
service for ``wholesale purchases'' under its own tariff. As discussed 
below, we clarify that a transmission provider does not have to ``take 
service'' under its own tariff for the transmission of power that is 
purchased on behalf of bundled retail customers.
    In a situation in which a transmission provider purchases power on 
behalf of its retail native load customers, the Commission does not 
have jurisdiction over the transmission of the purchased power to the 
bundled retail customers insofar as the transmission takes place over 
such transmission provider's facilities,<SUP>128 and therefore the pro 
forma tariff does not have to be used for such transmission. Moreover, 
we recognize that purchases made collectively on behalf of native load 
<SUP>129 cannot necessarily be identified as going to any particular 
customer. However, the Commission does have jurisdiction over 
transmission service associated with sales to any person for resale, 
and such transmission must be taken under the transmission provider's 
pro forma tariff. <SUP>130
---------------------------------------------------------------------------

    \128\ To the extent the transmission takes place on the 
interstate facilities of other public utilities, we would have 
jurisdiction over such transmission.
    \129\ Native load means ``[t]he 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.'' Section 1.19 of the pro forma 
tariff.
    \130\ All transmission in interstate commerce by a public 
utility in conjunction with a sale for resale of electric energy is 
jurisdictional and must be taken under a FERC-jurisdictional tariff. 
The same is true for all unbundled transmission in interstate 
commerce to wholesale customers, as well as to unbundled retail 
customers.
---------------------------------------------------------------------------

    Order No. 888, relying on the principle of comparability, 
established the terms and conditions for network service provided to 
network customers under the pro forma tariff. Network customers may 
include the transmission provider itself as well as any other entity 
receiving Network Integration Service. If the transmission provider 
purchases energy from another power supplier in order to make sales to 
its wholesale native load customers, it must take the transmission 
service necessary to transmit the power from its point(s) of receipt to 
its point(s) of delivery under the same terms and conditions as other 
Network Customers.<SUP>131 As we explained in AES Power, Inc., network 
customers are entitled to make economy energy purchases from non-
designated network resources at no additional charge on a basis 
comparable to the economy energy purchases made by the transmission 
provider on behalf of its bundled retail customer.<SUP>132 This applies 
to the transmission provider as a network transmission customer under 
its own tariff as well as to other network transmission customers that 
make economy energy purchases on behalf of their customers. Thus, 
insofar as all wholesale transmission customer usage is concerned, 
third-party network customers are treated the same as the transmission 
owner.
---------------------------------------------------------------------------

    \131\ Under the Order No. 888 pro forma tariff, third-party 
wholesale customers have the ability to obtain the identical service 
the transmission provider provides itself when it engages in a sale 
of electric energy for resale. This may include network or point-to-
point service.
    \132\ 69 FERC ] 61,145 at 62,300 (1994) (proposed order), 74 
FERC ] 61,220 (1996) (final order).
---------------------------------------------------------------------------

2. Service that Must be Provided by Transmission Provider
    In the Final Rule, the Commission found that a public utility must 
offer transmission services that it is reasonably capable of providing, 
not just those services that it is currently providing to itself or 
others. <SUP>133 The Commission explained that because a public utility 
that is reasonably capable of providing transmission services may 
provide itself such services at any time it finds those services 
desirable, it is irrelevant that it may not be using or providing that 
service today. However, the Commission explained that if a customer 
seeks a customized service not offered in an open access tariff, a 
customer may, barring successful negotiation for such service, file a 
section 211 application.
---------------------------------------------------------------------------

    \133\ FERC Stats. & Regs. at 31,690; mimeo at 160.
---------------------------------------------------------------------------

Rehearing Requests

    Cleveland requests that the Commission make explicit that 
comparability will be evaluated not only by reference to a transmission 
provider's wholesale services, but also by comparison to the terms, 
conditions, and prices applicable to its retail services, whether 
bundled or unbundled. Cleveland asserts that this is needed so that 
TDUs are not at a competitive disadvantage in competing with the 
transmission provider for retail customers. It maintains that this is 
consistent with the Transmission Pricing Policy and established 
precedent.

Commission Conclusion

    No clarification is necessary. In determining what transmission 
services a utility must offer for wholesale sales of electric energy in 
interstate commerce, the Final Rule explicitly states that ``a public 
utility must offer transmission services that it is reasonably capable 
of providing, not just those services that it is currently providing to 
itself or others.'' <SUP>134 Further, the Final Rule requires that 
network service customers receive service comparable to the service 
provided to the transmission provider's native load. Because the Rule 
applies to retail transmission that is voluntarily offered or pursuant 
to a state retail access program, the requirements to offer services 
that the utility is reasonably capable of providing and services 
comparable to those provided to native load would also apply to retail 
service in these limited retail circumstances.
---------------------------------------------------------------------------

    \134\ FERC Stats. & Regs. at 31,690; mimeo at 160.
---------------------------------------------------------------------------

3. Who Must Provide Non-discriminatory Open Access Transmission
    In the Final Rule, the Commission explained that its authority 
under sections 205 and 206 of the FPA permits it to require only public 
utilities to file open access tariffs as a remedy for undue 
discrimination.<SUP>135 The Commission further explained that it has no 
authority under those sections of the FPA to require non-public 
utilities to file tariffs with the Commission.
---------------------------------------------------------------------------

    \135\ FERC Stats. & Regs. at 31,691-92; mimeo at 162-65.
---------------------------------------------------------------------------

    The Commission also discussed three mechanisms that would help 
alleviate the problems associated with not being able to require non-
public utilities to provide open access: (1) Broad application of 
section 211; (2) the reciprocity requirement set forth in the Final 
Rule; and (3) the formation of RTGs.
    The Commission also indicated that it will not allow public 
utilities that jointly own interstate transmission facilities with non-
jurisdictional entities to escape the requirements of open access. 
Thus, the Commission required each public utility that owns interstate 
transmission facilities jointly with a non-jurisdictional entity to 
offer service over its share of the joint facilities, even if the joint 
ownership contract prohibits service to third parties. The Commission 
required the public utilities, in a section 206 compliance filing, to 
file with the Commission, by December 31, 1996, a proposed revision 
(mutually agreeable

[[Page 12300]]

or unilateral) to their contracts with non-jurisdictional owners.

Rehearing Requests

Jointly-Owned Facilities

    Union Electric argues that the Final Rule improperly requires a 
public utility to unilaterally file a modification to agreements that a 
non-jurisdictional entity opposes, which amounts to a litigation 
coercion provision. Union Electric notes that it has been told by 
Associated Electric Cooperative, Inc. that it will oppose any 
modifications to Union Electric's agreements. Union Electric further 
states that these facilities are not commonly owned, but rather each 
party wholly owns its segment of the facilities.
    Dalton asserts that Georgia Power Company cannot comply with the 
requirement to offer service over its share of joint facilities because 
the ITS is not owned by members as tenants in common, but instead each 
member owns specific segments of the transmission grid. Dalton further 
argues that it is unjust and unreasonable to require Georgia Power 
Company to give access to the ITS to new and roll-over transmission 
customers under the Order No. 888 tariff that are unwilling to accept 
an investment responsibility and an obligation to make balancing 
payments.
    Associated EC argues that the Commission may modify non-
jurisdictional contracts only under section 211 of the FPA; the 
Commission cannot simply modify the contract with respect to the public 
utility.
    NE Public Power District states that it is party to an agreement 
with a public utility involving jointly constructed transmission 
facilities that prohibits use of the transmission capacity by a non-
party. It asserts that ``[t]he District's contractual rights under its 
contract constitute valuable property, and the summary annulment of 
those rights constitutes a violation of Due Process.'' (NE Public Power 
District at 18-20). Moreover, it argues that blanket invalidation of 
the terms and conditions of the contracts is contrary to the Sierra-
Mobile doctrine.

Commission Conclusion

    We reject those arguments that maintain that the Commission cannot 
properly require a public utility to file unilaterally a modification 
to agreements concerning joint transmission facilities that a non-
jurisdictional entity opposes. It is without question that the 
Commission has the exclusive authority to regulate public utilities 
engaged in the sale for resale and/or transmission of electric energy 
in interstate commerce to assure that rates, terms and conditions are 
just and reasonable and not unduly discriminatory. The fact that a 
public utility may jointly own, with a non-jurisdictional entity, 
transmission facilities through which it engages in sales for resale 
and/or transmission of electric energy in interstate commerce does not 
alter the Commission's authority to regulate that public 
utility.<SUP>136 If the Commission finds that a matter needs to be 
remedied, it may issue an order directed at the public utility. The 
fact that such an order may affect a non-jurisdictional joint owner 
does not undermine the validity of the Commission's order.<SUP>137 
Otherwise, a public utility could simply enter into joint agreements 
with non-jurisdictional utilities to the frustration of the 
Commission's mandate to protect consumers from undue 
discrimination.<SUP>138
---------------------------------------------------------------------------

    \136\ See Policy Statement Regarding Regional Transmission 
Groups, 64 FERC para. 61,139 at 61,993 (1993); Midwest Power 
Systems, Inc., 69 FERC para. 61,025 at 61,104-05 (1994). Nor does 
the form of ownership of the joint facilities have any bearing on 
the Commission's jurisdiction over public utilities.
    \137\ Though the non-jurisdictional entity would not become 
subject to Commission regulation.
    \138\ Cf. H.K. Porter Co., Inc. v. Central Vermont Railway, 
Inc., 366 U.S. 272, 273-75 (1961).
---------------------------------------------------------------------------

    Nor does the exercise of the Commission's powers under the FPA to 
remedy undue discrimination by public utilities constitute a violation 
of due process vis-a-vis the non-jurisdictional entity. When the 
contract was entered into and filed with the Commission it was with the 
explicit knowledge that the Commission could regulate the rates, terms 
and conditions of the contract with respect to the jurisdictional 
services provided thereunder by the public utility. If and when a 
public utility unilaterally files either to amend or terminate the 
agreement, the non-jurisdictional party is free to raise any arguments 
it wishes to support its position that no changes are necessary to 
ensure that the contract is just and reasonable and not unduly 
discriminatory or preferential.
4. Reservation of Transmission Capacity by Transmission Customers
    In the Final Rule, the Commission concluded that firm transmission 
customers, including network customers, should not lose their rights to 
firm capacity simply because they do not use that capacity for certain 
periods of time.<SUP>139
---------------------------------------------------------------------------

    \139\ FERC Stats. & Regs. at 31,693; mimeo at 168-70.
---------------------------------------------------------------------------

Rehearing Requests

    No rehearing requests addressed this matter.
5. Reservation of Transmission Capacity for Future Use by Utility
    In the Final Rule, the Commission concluded that public utilities 
may reserve existing transmission capacity needed for native load 
growth and network transmission customer load growth reasonably 
forecasted within the utility's current planning horizon.<SUP>140 
However, the Commission determined that any such capacity that a public 
utility reserves for future growth, but is not currently needed, must 
be posted on the OASIS and made available to others through the 
capacity reassignment requirements, until such time as it is actually 
needed and used.
---------------------------------------------------------------------------

    \140\ FERC Stats. & Regs. at 31,694; mimeo at 172.
---------------------------------------------------------------------------

Rehearing Requests

    CCEM argues that it is discriminatory to allow public utilities and 
network transmission customers to reserve existing transmission 
capacity for their native load growth because it (1) limits the 
determination of ATC, (2) is likely to increase the cost of 
transmission for other customers, and (3) is inconsistent with a 
capacity reservation-based system. CCEM argues, however, that if the 
reservation feature is retained, franchise utilities that reserve 
capacity must pay the full reservation charges, with no cost shifting 
to other customers. CCEM further recommends that all reservation 
payments should be credited directly to firm transmission services and 
the planning horizon should be limited to a reasonable time into the 
future.
    American Forest & Paper argues that to achieve comparability, 
utilities must not be permitted to withhold capacity from the market 
for the benefit of native load. American Forest & Paper further argues 
that the Commission must establish mechanisms for evaluating the 
reasonableness of the utilities' requirements and projections, 
otherwise they have an incentive to over-forecast and to extend their 
planning horizons. American Forest & Paper suggests that requiring 
utilities to establish separate entities to purchase transmission on 
behalf of their native load would help solve this problem.
    VA Com requests that the Commission clarify what will happen if a 
utility's forecast of load growth is too low. It argues that native 
load should not have to bear the burden of any forecast errors and that 
utilities should be required to reserve sufficient capacity to serve 
the current and projected needs

[[Page 12301]]

of native load customers. VA Com would also have the definition of 
native load in section 1.19 of the tariff expanded to include existing 
distribution cooperatives and others who currently provide service to 
end users. With respect to reservation priority, VA Com states that the 
Commission should establish the following reservation priority: native 
load customers, firm contract customers, and non-firm customers. 
Finally, VA Com asserts that the calculation of ATC must not include 
any capacity that may be needed by native load customers.

Commission Conclusion

    We will deny the requests of CCEM and American Forest and Paper. We 
continue to believe that public utilities should be allowed to reserve 
existing transmission capacity needed for native load growth and 
network customer load growth reasonably forecasted within the utility's 
current planning horizon.
    We note that network service is founded on the notion that the 
transmission provider has a duty to plan and construct the transmission 
system to meet the present and future needs of its native load and, by 
comparability, its third-party network customers. In return, the native 
load and third-party network customers must pay all of the system's 
fixed costs that are not covered by the proceeds of point-to-point 
service. This means that native load and third-party network customers 
bear ultimate responsibility for the costs of both the capacity that 
they use and any capacity that is not reserved by point-to-point 
customers. In this regard, native load and third-party network 
customers face a payment risk that point-to-point customers generally 
do not face. For these reasons, we do not believe that it is 
appropriate to require native load and network customers to assume any 
additional cost responsibility for the capacity that is reserved for 
their future use.
    In response to CCEM's concerns, we recognize that offering load-
based network service and reservation-based point-to-point service in 
one tariff may have disadvantages in that it may result in less than 
optimal use of the system if a utility overestimates its load. However, 
by requiring that available capacity reserved for native load be posted 
on OASIS and be available to others except when actually needed to 
serve native load, we believe Order No. 888 substantially relieves the 
incentive to over-reserve for native load and goes a long way toward 
assuring full and efficient use of the system.
    With regard to the concern raised by VA Com, the transmission 
provider has an ongoing duty to plan and construct its system in a 
prudent manner in order to meet all of its firm service obligations. We 
also reiterate that

public utilities may reserve existing transmission capacity needed 
for native load growth and network transmission customer load growth 
reasonably forecasted within the utility's current planning 
horizon.<SUP>[141]

    \141\ FERC Stats. & Regs. at 31,694; mimeo at 172.
---------------------------------------------------------------------------

There is a risk of under-or over-projecting the transmission needs of 
native load and network customers, and the native load and network 
customers' cost responsibilities reflect this additional risk. In 
response to VA Com's request, we note that nothing in our regulations 
prohibits a state commission from overseeing a utility's retail native 
load growth projections. Finally, concerns regarding the accuracy of 
load growth projections for native load and network customers may be 
raised when a transmission service agreement is filed with the 
Commission or in a separate section 206 proceeding.
6. Capacity Reassignment
    In the Final Rule, the Commission concluded that a public utility's 
tariff must explicitly permit the voluntary reassignment of all or part 
of a holder's firm transmission capacity rights to any eligible 
customer.<SUP>142
---------------------------------------------------------------------------

    \142\ FERC Stats. & Regs. at 31,696; mimeo at 178-179.
---------------------------------------------------------------------------

(1) Reassignable Transmission Services
    The Commission concluded that point-to-point transmission service 
should be reassignable, but that network transmission service is not 
reassignable.<SUP>143
---------------------------------------------------------------------------

    \143\ FERC Stats. & Regs. at 31,696; mimeo at 179.
---------------------------------------------------------------------------

(2) Terms and Conditions of Reassignments
a. General
    In effecting a reassignment, the Commission found that the assignor 
may deal directly with an assignee without involvement of the 
transmission provider.<SUP>144 Alternatively, the Commission explained 
that the assignor may request the transmission provider to effect a 
reassignment on its behalf, in which case the transmission provider 
must post the available capacity on its OASIS and assure that any 
revenues associated with the reassignment are credited to the assignor. 
The Commission further found that, among other things, any assignment 
must be posted on the transmission provider's OASIS within a reasonable 
time after its effective date.
---------------------------------------------------------------------------

    \144\ FERC Stats. & Regs. at 31,696-97; mimeo at 179-80.
---------------------------------------------------------------------------

b. Contractual Obligations
    The Commission concluded that while assignors and assignees may 
contract directly with each other, the assignor will remain obligated 
to the transmission provider and the assignee will be liable solely to 
the assignor.<SUP>145 The Commission, however, did permit mutually 
agreeable alternatives to this approach.
---------------------------------------------------------------------------

    \145\ FERC Stats. & Regs. at 31,697; mimeo at 180-81.
---------------------------------------------------------------------------

c. Price Cap
    The Commission concluded that the rate for any capacity 
reassignment must be capped by 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 capped at the cost of expansion (Price Cap).<SUP>146
---------------------------------------------------------------------------

    \146\ FERC Stats. & Regs. at 31,697; mimeo at 181.
---------------------------------------------------------------------------

Rehearing Requests

Scheduling Transmission Service by Assignees

    CCEM requests that the Commission clarify that an assignee of 
transmission capacity, or its agent, is permitted to schedule 
transmission service directly with the transmission provider.

Network Transmission Service

    American Forest & Paper declares that the Commission erred in 
finding that network service is not reassignable. American Forest & 
Paper argues that there is no technical reason for the Commission's 
position. According to American Forest & Paper, the Commission merely 
perpetuates the myth that in point-to-point transmission the contract 
actually determines the path of the flow of electrons. In fact, 
American Forest & Paper argues, the only issue is arriving at a 
nondiscriminatory and equitable price.
    VT DPS argues that there is no reason network capacity rights 
cannot be defined during the period of a reassignment as VT DPS 
suggested in its comments:

    Section 2.6 of the NorAm NIS Rate Schedule (Appendix B to the 
Initial NOPR comments of VDPS) is a provision which allows the 
reassignment of network service. Reassignment under the NorAm tariff 
would work this way: During the period of the assignment, both the 
original and replacement customers' network service entitlements are 
defined as specified contract quantities, the sum of which is equal 
to the original customer's highest coincident peak load during the 
12 months preceding the

[[Page 12302]]

assignment. During the period of the assignment, that contract 
quantity, not the actual use of the system by the original and 
replacement shipper, will be used to determine the two customers' 
load ratio share responsibility. The original and replacement 
customers are free to divide responsibility for interim contract 
demand between them as they see fit.[<SUP>147]

    \147\ VT DPS at 47-48; see also Valero at 29-31.
---------------------------------------------------------------------------

    PA Coops argue that the Commission failed to explain why network 
customers have no capacity rights and points to a statement in Order 
No. 888 that network customers ``should not lose their rights to firm 
capacity'' as being inconsistent with the Commission's conclusion with 
respect to the reassignment of network service.
    AMP-Ohio asserts that absent an ongoing pass-through to network 
customers of the revenue credits associated with sales of point-to-
point service, the Commission should permit the reassignment of unused 
transmission capacity by network customers.
    TDU Systems argue that the Commission should permit the assignment 
of a network customer's right to network transmission service for 
certain specific purposes. In particular, TDU Systems state that the 
Commission should permit assignment to allow a customer to coordinate, 
jointly operate, or pool its system with the systems of other local and 
regional network customers. TDU Systems argue that this provides an 
opportunity to maximize efficiencies without presenting the 
complication that the Commission has perceived with respect to the 
reassignment of point-to-point transmission capacity.

Price Cap

    EEI asserts that the Commission's price cap creates several 
problems: (1) non-comparable treatment because transmission providers 
must credit revenues, but resellers can keep the revenues; (2) allowing 
sale at a price higher than paid could encourage speculation and 
hoarding; and (3) the transmitting utility's maximum stated rate should 
not include the utility's opportunity costs.
    CCEM argues that transmission customers that are not transmission 
providers or affiliates of transmission providers should be freed from 
the price cap. CCEM claims that in a secondary market at market-based 
prices, opportunity costs can be communicated and lost opportunity 
costs averted.
    NRECA believes that the price cap provision that permits an 
assignor to assign capacity at its own opportunity costs (capped at the 
cost of expansion) may provide firm point-to-point customers a strong 
economic incentive to buy up substantial firm capacity for speculative 
purposes and argues that this provision should be eliminated. NRECA 
also argues that this provision presents difficult rate substantiation 
questions when the assignor is not a public utility. Further, NRECA and 
SoCal Edison note that section 23.1 of the tariff does not include the 
cap at the cost of expansion.

Calculation of Assignor's Opportunity Costs

    SoCal Edison asserts that the Commission must indicate how an 
assignor should calculate its own opportunity costs with respect to 
determining the price cap and should indicate that an assignor must 
abide by the same standard for recovering opportunity costs as the 
transmission provider. Carolina P&L also asserts that assignors must be 
held to the same standard as transmission providers when calculating 
opportunity costs. Carolina P&L further explains that if the 
opportunity costs are based on the cost of foregone transactions, the 
assignor should be required to post the price on OASIS.
    Carolina P&L also asks that the Commission clarify how an assignor 
is to calculate its own opportunity costs. In particular, Carolina P&L 
asks if an assignor is limited to recovering the opportunity costs to 
which it is subject under the transmission provider's tariff or can the 
assignor forfeit the transaction underlying the transmission service 
and call the resulting difference an opportunity cost?

Resellers Into the Secondary Market

    CCEM argues that the Commission should free resellers, ``who but-
for the resell would not be public utilities,'' from regulation as 
public utilities or should minimize the regulatory burden on 
them.<SUP>148 It further asserts that resellers that are not 
transmission providers should be treated like unaffiliated power 
marketers and granted waivers from public utility regulations.
---------------------------------------------------------------------------

    \148\ CCEM makes this argument in its rehearing request of Order 
No. 889.
---------------------------------------------------------------------------

Participation in the Secondary Market

    CCEM argues that those customers that are permitted to continue to 
take service under existing agreements ``should be excluded from 
participating in the secondary market until such time as they agree to 
comply with the pro forma tariff.'' (CCEM (889 rehearing request) at 
7).

Commission Conclusion

Scheduling Transmission Service by Assignee

    The pro forma tariff does not prohibit the assignee of transmission 
capacity from scheduling transmission service with the transmission 
provider. In fact, the tariff provides that ``the Assignee will be 
subject to all terms and conditions of this Tariff'' (tariff section 
23.1), which would include the scheduling provision of tariff sections 
13.8 and 14.6.

Network Transmission Service

    We reaffirm our conclusion that network transmission service is not 
reassignable in the secondary market.<SUP>149 Parties have raised no 
new arguments that would persuade us otherwise. PA Coops are 
nevertheless correct in noting that network customers do have rights to 
firm capacity. However, a network customer's rights (as well as the 
transmission provider's planning responsibilities) are defined only in 
terms of the capacity needed to integrate the network customer's 
designated resources and its designated loads. These are usage- or 
load-based rights that are not fixed; they vary as the customer's load 
varies. Thus, the network customer's capacity rights are not well 
enough defined to be generally reassignable in the secondary 
market.<SUP>150
---------------------------------------------------------------------------

    \149\ While portions of network transmission service are not 
reassignable, we would permit the reassignment of a particular 
network transmission service in its entirety.
    \150\ We note that the question of how network service may be 
converted into a service that is reassignable is at issue in the 
Capacity Reservation Tariff NOPR proceeding in Docket No. RM96-11-
000.
---------------------------------------------------------------------------

    VT DPS proposes a formula for defining a network customer's 
entitlement that would be operative during the period of an assignment. 
However, the proposed definition is simply an artifice derived from the 
load ratio share calculation. The formula does not result in a 
reassignable capacity right.
    AMP-Ohio's suggestion regarding the proper treatment of the revenue 
credits associated with point-to-point service raises a rate issue that 
should be addressed in a ratemaking proceeding. However, we note that 
the proper treatment of such credits does not turn on the assignability 
of network service.
    Finally, TDU Systems' recommendation that network service be 
reassignable only for pooling and coordination purposes is without 
merit. If customers wish to avail themselves of network service in 
order to realize

[[Page 12303]]

benefits associated with joint or coordinated operations with other 
systems, they can jointly request network service from the transmission 
provider. To allow customers to opt into and out of network service 
arrangements under the guise of capacity reassignment would be an abuse 
of the terms and conditions of the service, which, among other things, 
requires the transmission provider to plan for the long-term needs of 
network customers.

Price Cap

    We will also reaffirm our conclusions regarding the price cap 
applicable to capacity reassignment. We continue to believe that 
customers must be given limited pricing flexibility in order to achieve 
the full efficiency and risk management benefits of capacity 
reassignment.
    Contrary to the assertions of EEI and NRECA, we are not persuaded 
that allowing the customer to reassign capacity at a rate higher than 
it paid, as a result of charging its own opportunity costs, will lead 
to speculation and hoarding. As a condition of the open access tariff, 
the Commission will require customers reassigning transmission capacity 
to fully develop their method for calculating opportunity costs and 
provide all information necessary to their customers in order to verify 
such costs. Further, we reiterate that the potential for hoarding can 
be mitigated by (1) allowing the transmission provider to sell any 
reserved but unscheduled point-to-point transmission capacity on a non-
firm basis, and (2) having a price cap, which allows the reseller to 
charge no more than a cost-based rate, including its own opportunity 
cost for reassigned capacity. Therefore, the reseller will find that 
reassigning transmission capacity to others with higher valued uses 
will be in its economic self interest. In addition, any hoarding of 
capacity that has anticompetitive effects can be addressed under 
section 206.
    We deny CCEM's request to remove the price cap for transmission 
customers that are not transmission providers or affiliates of 
transmission providers. As we stated in the Final Rule, we are unable 
to conclude that competition in the market for reassigned transmission 
capacity is sufficient to prevent assignors from exerting market power. 
Thus, we believe the opportunity cost cap should be retained.<SUP>151
---------------------------------------------------------------------------

    \151\ We note that if the assignor is a public utility it will 
in any event have to file a rate schedule for the re-sale 
(reassignment) of unbundled transmission.
---------------------------------------------------------------------------

    Finally, in response to EEI's request, we clarify that ``the 
transmission provider's maximum stated firm transmission rate in effect 
at the time of the reassignment'' does not include the transmission 
provider's opportunity costs.<SUP>152 Also, as suggested by NRECA and 
others, section 23.1 of the pro forma tariff will be revised to 
indicate that the assignor's opportunity costs are capped at the 
transmission provider's cost of expansion.
---------------------------------------------------------------------------

    \152\ We also reject as unsupported EEI's comparability argument 
that transmission providers must treat any transmission service 
revenues as a revenue credit, but the reseller may keep any 
transmission resale revenues.
---------------------------------------------------------------------------

Calculation of Assignor's Opportunity Costs

    In response to the requests of SoCal Edison and Carolina P&L, we 
clarify that the assignor's opportunity costs should be measured in a 
manner that is analogous to that used to measure the transmission 
provider's opportunity costs. That is, an assignor's opportunity costs 
include: (1) increased costs associated with changes in power purchases 
or in the dispatch of generating units necessary to accommodate a 
reassignment, and (2) decreased revenues that arise from the assignor 
having to reduce sales of power in order to effect the 
reassignment.<SUP>153
---------------------------------------------------------------------------

    \153\ In response to Carolina P&L's request, we clarify that the 
assignor is not limited to recovering the opportunity costs to which 
it is subject under the transmission provider's tariff, i.e., the 
transmission provider's opportunity costs.
---------------------------------------------------------------------------

    Regarding the calculation of opportunity costs, we intend to hold 
assignors to the same general standard as transmission providers. Thus, 
consistent with our treatment of transmission providers, we will not 
require assignors to post their opportunity costs on the OASIS or to 
make the costs routinely available to the public. We will, however, 
require assignors to describe to their assignees their derivation of 
opportunity costs in sufficient detail to satisfy the assignees that 
the price charged does 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, as set forth in section 23.1 of the tariff.

Resellers Into the Secondary Market

    The issues raised by CCEM with respect to the regulation of 
resellers into the secondary market are fact specific and, accordingly, 
we will address such issues on a case-by-case basis.

Participation in the Secondary Market

    We reject CCEM's argument that those customers that are permitted 
by Order No. 888 to continue to take service under existing agreements 
should be denied access to the secondary market until they agree to 
comply with the pro forma tariff. CCEM's approach would undermine our 
determination not to generically abrogate existing agreements, and 
would slow the growth of the secondary market by limiting the number of 
eligible participants.
7. Information Provided to Transmission Customers
    In the Final Rule, the Commission concluded that all necessary 
transmission information, as detailed in the OASIS Final Rule, must be 
posted on an OASIS.<SUP>154
---------------------------------------------------------------------------

    \154\ FERC Stats. & Regs. at 31,698; mimeo at 183-84.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
8. Consequences of Functional Unbundling
a. Distribution Function
    In the Final Rule, the Commission concluded that the additional 
step of functionally unbundling the distribution function from the 
transmission function is not necessary at this time to ensure non-
discriminatory open access transmission.<SUP>155
---------------------------------------------------------------------------

    \155\ FERC Stats. & Regs. at 31,699; mimeo at 186.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
b. Retail Transmission Service
    In the Final Rule, the Commission explained that although the 
unbundling of retail transmission and generation, as well as wholesale 
transmission and generation, would be helpful in achieving 
comparability, it did not believe it was necessary.<SUP>156 The 
Commission further explained that the matter raises numerous difficult 
jurisdictional issues that are more appropriately considered when the 
Commission reviews unbundled retail transmission tariffs that may come 
before the Commission in the context of a state retail wheeling 
program.
---------------------------------------------------------------------------

    \156\ FERC Stats. & Regs. at 31,699-700; mimeo at 188.
---------------------------------------------------------------------------

Rehearing Requests

    CCEM argues that all transmission must be unbundled, including 
currently bundled retail transmission service, because failure to do so 
is inconsistent with the Commission's assertion of jurisdiction over 
the rates, terms, and conditions of unbundled interstate transmission 
to retail customers and

[[Page 12304]]

authority to address retail stranded costs through its jurisdiction 
over such costs. CCEM notes that the Commission found it necessary in 
Order No. 636 to unbundle the pipeline's direct retail sales to achieve 
comparability (CCEM cites FPC v. Conway Corp., 426 U.S. 271, 273 (1976) 
and Mississippi River Transmission Corp. v. FERC, 969 F.2d 1215 (D.C. 
Cir. 1992) for the proposition that the Commission has jurisdiction 
over all interstate transmission).
    NY Municipal Utilities and American Forest & Paper also argue that 
the Commission erred in not requiring the unbundling of the 
transmission component of retail sales. American Forest & Paper 
believes that such unbundling will facilitate competition by making the 
generation price transparent to all participants.

Commission Conclusion

    We disagree with those entities that argue that the Commission 
erred in not requiring the unbundling of all transmission service, 
including the unbundling of transmission from retail service. As we 
explained in the Final Rule:

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. Under the FPA, the Commission's 
jurisdiction over sales of electric energy extends only to wholesale 
sales. However, when a retail transaction is broken into two 
products that are sold separately (perhaps by two different 
suppliers: an electric energy supplier and a transmission supplier), 
we believe the jurisdictional lines change. In this situation, the 
state clearly retains jurisdiction over the sale of the power. 
However, the unbundled transmission service involves only the 
provision of ``transmission in interstate commerce'' which, under 
the FPA, is exclusively within the jurisdiction of the Commission. 
Therefore, when a bundled retail sale is unbundled and becomes 
separate transmission and power sales transactions, the resulting 
transmission transaction falls within the Federal sphere of 
regulation.<SUP>157

    \157\ FERC Stats. & Regs. at 31,781; mimeo at 430-31 (emphasis 
in original). As discussed in Section IV.I., infra, we believe this 
jurisdictional determination is supported by the statute and the 
case law, including the D.C. Circuit's recent decision in United 
Distribution Companies v. FERC, 88 F.3d 1105 (1996).
---------------------------------------------------------------------------

    Nor is our decision not to unbundle transmission from retail 
generation service inconsistent with our assertion of jurisdiction over 
unbundled interstate transmission to retail customers. As we explained 
in the Final Rule and described further above, we have exclusive 
jurisdiction under the FPA over ``transmission in interstate commerce'' 
by public utilities, which includes the unbundled interstate 
transmission component of a previously bundled retail 
transaction.<SUP>158 Our assertion of jurisdiction in such a situation 
arises only if the retail transmission in interstate commerce by a 
public utility occurs voluntarily or as a result of a state retail 
program.
---------------------------------------------------------------------------

    \158\ FERC Stats. & Regs. at 31,781; mimeo at 431.
---------------------------------------------------------------------------

c. Transmission Provider
1. Taking Service Under the Tariff
    In the Final Rule, the Commission concluded that public utilities 
must take all transmission services for wholesale sales under new 
requirements contracts and new coordination contracts under the same 
tariff used by others (eligible customers).<SUP>159 For sales and 
purchases under existing bilateral economy energy coordination 
agreements, the Commission gave an extension until December 31, 1996 
for public utilities to take transmission service under the same tariff 
used by others. The Commission also gave an extension of time to 
December 31, 1996 for certain existing power pooling and other multi-
lateral coordination agreements to comply with this 
requirement.<SUP>160
---------------------------------------------------------------------------

    \159\ FERC Stats. & Regs. at 31,700-01; mimeo at 191. See also 
discussion infra at Section IV.G. Section 1.11 (and Section 13.3).
    \160\ By notice issued September 27, 1996 in Docket Nos. RM95-8-
000 and RM94-7-001, the Commission revised the compliance dates. It 
required joint pool-wide section 206 compliance tariffs to be filed 
no later than December 31, 1996, and pool members to begin taking 
service under the tariffs 60 days after the section 206 filing. It 
also gave members of public utility holding companies an extension 
of time to take service under their system-wide tariff until no 
later than March 1, 1997.
---------------------------------------------------------------------------

Rehearing Requests

    This issue is discussed above in Section IV.C.1.b.
2. Accounting Treatment
    In the Final Rule, the Commission directed utilities to account for 
all uses of the transmission system and to demonstrate that all 
customers (including the transmission provider's native load) bear the 
cost responsibility associated with their respective uses.<SUP>161
---------------------------------------------------------------------------

    \161\ FERC Stats. & Regs. at 31,703; mimeo at 198.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.

D. Ancillary Services

    In the Final Rule, the Commission concluded that the following six 
ancillary services must be included in an open access transmission 
tariff: (1) Scheduling, System Control and Dispatch Service; (2) 
Reactive Supply and Voltage Control from Generation Sources Service; 
(3) Regulation and Frequency Response Service; (4) Energy Imbalance 
Service; (5) Operating Reserve--Spinning Reserve Service; and (6) 
Operating Reserve--Supplemental Reserve Service.<SUP>162 The Commission 
adopted NERC's recommendations for ancillary service definitions and 
descriptions with modifications.<SUP>163
---------------------------------------------------------------------------

    \162\ FERC Stats. & Regs. at 31,703-04; mimeo at 199.
    \163\ In comments on the proposed rule, NERC identified 
additional interconnected operations services that it indicated may 
be necessary for reliability. As discussed in the Final Rule, we do 
not require the transmission provider to be the default provider of 
these other services.
---------------------------------------------------------------------------

    The Commission determined that the transmission provider must 
provide and the transmission customer must purchase from the 
transmission provider the first two services, subject to conditions set 
out in the Rule. The transmission provider must offer the remaining 
four services to the transmission customer serving load in the 
transmission provider's control area. The transmission customer that is 
serving load in the transmission provider's control area must acquire 
these four services from the transmission provider or a third party, or 
self provide.
1. Specific Ancillary Services
a. Scheduling, System Control and Dispatch Service
    In the Final Rule, the Commission concluded that Scheduling, System 
Control and Dispatch Service is necessary to the provision of basic 
transmission service within every control area.<SUP>164 The Commission 
further stated that this service can be provided only by the operator 
of the control area in which the transmission facilities used are 
located.
---------------------------------------------------------------------------

    \164\ FERC Stats. & Regs. at 31,716; mimeo at 238.
---------------------------------------------------------------------------

Rehearing Requests

    Wisconsin Municipals asks that the Commission eliminate Schedule 1 
(Scheduling, System Control and Dispatch Service) as an ancillary 
service and require transmission providers to include these costs in 
the transmission revenue requirement so the transmission provider 
cannot recover these costs twice. Alternatively, Wisconsin Municipals 
asks that, if customers do their own scheduling through an electronic 
data link, the charge for scheduling and dispatch be waived.

Commission Conclusion

    We disagree with Wisconsin Municipals that we should eliminate this 
ancillary service and include its

[[Page 12305]]

costs with the transmission revenue requirement. Scheduling requires 
action by both the customer who provides information about a 
transaction and the control area that evaluates and accepts (schedules) 
the transaction. If a transmission provider allows a transmission 
customer to supply its schedules through an electronic data link, it is 
merely offering an alternate method of providing the transaction 
information required. The control area must still decide whether it can 
schedule a transaction. Further, scheduling a transaction is only one 
aspect of Scheduling, System Control and Dispatch Service. A control 
area must also dispatch generating resources to maintain generation/
load balance and maintain security during the transaction. Only the 
control area operator can perform these functions. A transmission 
provider must unbundle the cost of these functions, including 
scheduling, from its base transmission rate. This requirement to 
unbundle ancillary services costs from the base transmission rate 
ensures that double recovery of scheduling costs will not occur.
b. Reactive Supply and Voltage Control From Generation Sources Service
    In the Final Rule, the Commission concluded that Reactive Supply 
and Voltage Control from Generation Sources Service is necessary to the 
provision of basic transmission service within every control 
area.<SUP>165 Although a customer is required to take this ancillary 
service from the transmission provider or control area operator, the 
Commission stated that a customer may reduce the charge for this 
service to the extent it can reduce its requirement for reactive power 
supply.
---------------------------------------------------------------------------

    \165\ FERC Stats. & Regs. at 31,716-17; mimeo at 239.
---------------------------------------------------------------------------

Rehearing Requests

    NRECA and TDU Systems ask that Schedule 2 of the tariff, Reactive 
Supply and Voltage Control from Generation Sources Service, be modified 
to reflect that generation facilities outside a control area can 
provide reactive power. They argue that parties other than the 
transmission provider and the transmission customer are able to supply 
reactive power. Similarly, Santa Clara and Redding ask the Commission 
to revise Schedule 2 to require the transmission provider to offer this 
service, but to allow the transmission customer to arrange for this 
service through a purchase from the transmission provider, self-
provision, or purchases from third parties.<SUP>166 Blue Ridge also 
argues that the Commission should permit self-supply or other local 
supply when it is feasible and economic to do so.
---------------------------------------------------------------------------

    \166\ See also Cajun. Cajun notes that it does and could 
continue to provide at least a portion of reactive power.
---------------------------------------------------------------------------

    APPA, Santa Clara, Redding and Cajun point out an inconsistency 
between Schedule 2 and the preamble. They assert that Schedule 2 of the 
tariff should be revised to reflect the preamble language that allows a 
transmission customer to supply at least a portion of its reactive 
power service. California DWR says that it is capable of providing 
Reactive Supply and Voltage Control from Generation Sources Service and 
that mandating that it purchase this ancillary service makes no sense. 
California DWR asks the Commission to clarify that it is not required 
to purchase this ancillary service.
    TAPS asks the Commission to make clear that (1) customer-owned 
generation facilities that are available to supply reactive power to 
the transmission provider's transmission system receive a credit, (2) 
the extent of customer-supplied reactive power may be sufficient to 
eliminate the need for a separate reactive power charge paid to the 
transmission provider, and (3) customer-owned generation outside the 
control area may be eligible for a credit if it is located nearby where 
it can provide reactive support for the transmission provider's 
transmission system.<SUP>167 TAPS further asserts that reactive supply 
service should be viewed not on a transaction basis but on a gridwide 
or regionwide basis. Under this approach, according to TAPS, payments 
would be based on whether the user supplies more than it uses or uses 
more than it supplies.
---------------------------------------------------------------------------

    \167\ See also APPA.
---------------------------------------------------------------------------

Commission Conclusion

    Control area operators use sources of reactive support to control 
voltage and maintain a stable power supply system. Because of the 
limited ability to transmit reactive power, these facilities must be 
available at or near the point of need. Therefore, reactive power 
support, and hence the facilities able to provide (or absorb) reactive 
power, must be distributed throughout the transmission system for the 
reliable operation of the power system. Over- or under-supply of 
reactive power at other points in the network do not contribute to a 
stable system and could harm the reliability of the system.
    Although we agree with NRECA and TDU Systems that generation 
resources just outside the boundaries of a control area may provide 
some reactive support within the control area, the control area 
operator must be able to control the dispatch of reactive power from 
these generating resources. Accordingly, we will modify Schedule 2 to 
refer to generating facilities that are under the control of the 
control area operator instead of in the control area. The transmission 
customer's service agreement should specify the generating resources 
made available by the transmission customer that provide reactive 
support.
    As noted in the Final Rule, a transmission customer can reduce (but 
not eliminate completely) the reactive supply and voltage control needs 
and costs that its transaction imposes on the transmission provider's 
system. For example, a customer who controls generating units equipped 
with automatic voltage control equipment may be able to use those units 
to help control the voltage locally and reduce the reactive power 
requirement of the transaction.<SUP>168 However, if these units are not 
always available or are not subject to the direction of the control 
area operator, their occasional use may not reduce the investment 
required by the control area operator in reactive power facilities. It 
merely reduces temporarily the cost of operating these facilities. 
Consistent with this understanding, we will modify Schedule 2 of the 
tariff to allow a transmission customer to supply at least part of the 
reactive power service it requires. We will continue to require 
reactive power service to be provided by and purchased from the 
transmission provider. However, a transmission customer may satisfy 
part of its obligation through self-provision or purchases from 
generating facilities under the control of the control area operator. 
The transmission customer's service agreement should specify all 
reactive supply arrangements.
---------------------------------------------------------------------------

    \168\ The location and operating capabilities of the generator 
will affect its ability to reduce reactive power requirements.
---------------------------------------------------------------------------

    We deny the California DWR and TAPS request that customer-owned 
generation facilities that are available to supply reactive power 
should automatically receive a credit. However, as the Final Rule 
states, a customer may reduce the charge for this service to the extent 
it can reduce its requirement for reactive power supply. We do not 
believe a transmission customer can satisfy all of its reactive 
requirements or allow the transmission provider to avoid

[[Page 12306]]

investment in reactive power related facilities. Concerning the other 
request of TAPS, we will not require that the supply of reactive power 
be on a gridwide or regionwide basis. Because reactive power must be 
supplied near the point of need, we are not persuaded that gridwide 
supply is feasible.
c. Energy Imbalance Service
    In the Final Rule, the Commission concluded that Energy Imbalance 
Service must be offered for transmission within and into the 
transmission provider's control area to serve load in the area.<SUP>169 
However, the Commission noted, a transmission customer can reduce or 
eliminate the need for energy imbalance service in several ways.
---------------------------------------------------------------------------

    \169\ FERC Stats. & Regs. at 31,717; mimeo at 240.
---------------------------------------------------------------------------

    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. For minor hourly differences between the scheduled 
and delivered energy, the transmission customer is allowed to 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. A minor difference is one for which the actual energy 
delivery differs from the scheduled energy by less than 1.5 percent, 
except that any hourly difference less than one megawatt-hour is also 
considered minor. Thus, the Final Rule established an hourly energy 
deviation band of <plus-minus>/1.5 percent (with a minimum of 1 MW) for 
energy imbalance. The transmission customer must compensate the 
transmission provider for an imbalance that falls outside the hourly 
deviation band and for accumulated minor imbalances that are not made 
up within 30 days.
(1) Description of Energy Imbalance

Rehearing Requests

    North Jersey asserts that the definitions of Energy Imbalance 
Service and Backup Supply Service are conflicting and need 
clarification. North Jersey proposes that Energy Imbalance Service be 
clarified to state that a transmission provider will be required to 
supply power to a customer ``within the dispatch period of the 
transmission provider's tariff.'' It states that this assures power 
when a customer is unable to change its nominations to match its 
generation capabilities. On the other hand, North Jersey states that 
Backup Supply Service should be the supply of power for a period longer 
than the tariff dispatch period.
    NIMO asserts that the Commission should recognize that there is 
another type of Energy Imbalance Service. If a generator is located in 
one control area, but transfers the power to load in another control 
area, there is a potential mismatch between the amount of power 
scheduled for delivery by the generator and the amount it actually 
provides to the operator of the control area where it is located.
    Nebraska Public Power District (NPPD) states that allowing third 
parties to provide Energy Imbalance Service and Regulation and 
Frequency Response Service could jeopardize system reliability. It 
argues that the transmission provider must have the right to approve 
the third party provider of these services and the right to physically 
meter the loads located out of the transmission provider's control area 
or otherwise monitor these services to be assured that they are 
provided satisfactorily.
    NCMPA argues that because of the potential for abuse, the 
Commission should grant an exemption from an energy imbalance charge if 
the source of the energy shortfall is a generating resource that has 
been turned over to the transmission provider's dispatching control for 
meeting control area requirements.

Commission Conclusion

    We clarify that Energy Imbalance Service is used to supply energy 
for mismatches between scheduled deliveries and actual loads that may 
occur over an hour. We do not intend it to be used as a substitute for 
operating reserves when there is an outage of generation supply or 
transmission. The Final Rule states that if a customer uses either type 
of operating reserve, it must expeditiously replace the reserve with 
backup power to reestablish required minimum reserve levels.<SUP>170
---------------------------------------------------------------------------

    \170\ Order No. 888 imposes no obligation on the transmission 
provider to furnish replacement power on a long-term basis if the 
customer loses its source of supply.
---------------------------------------------------------------------------

    Order No. 888 specifies that there is no obligation on the 
transmission provider to provide power to the customer for a ``time 
longer than specified in the tariff'' for the customer's own backup 
supply to be made available.<SUP>171 The order also states that ``any 
arrangements for the supply of such service [i.e., Backup Supply 
Service] by the transmission provider should be specified in the 
customer's service agreement.'' <SUP>172 We revise the first statement 
to clarify that the transmission customer's service agreement, not the 
tariff, should specify any arrangements for backup service by the 
transmission provider, including the time within which backup power 
supply will be made available. The time should correspond to the time 
necessary to restore operating reserves that is generally accepted in 
the region and consistently followed by the transmission provider.
---------------------------------------------------------------------------

    \171\ FERC Stats. & Regs. at 31,711; mimeo at 222.
    \172\ FERC Stats. & Regs. at 31,711; mimeo at 223.
---------------------------------------------------------------------------

    NIMO asserts that two types of energy imbalance can occur if the 
generator and the load are in different control areas. These are (1) a 
mismatch between the energy scheduled to be received in the load's 
control area and the actual hourly energy consumed by the load, and (2) 
a mismatch between energy scheduled for delivery from the generator's 
control area and the amount of energy actually generated in the hour. 
The Energy Imbalance Service in the Final Rule applies to the first 
case only. Although we agree that the second type of mismatch can 
occur, we will not designate as Energy Imbalance Service a mismatch 
between energy scheduled and energy generated. Energy Imbalance Service 
in this Rule applies only to the obligation of the transmission 
provider to correct the first type of energy mismatch, one caused by 
load variations.
    In general, 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. The Energy Imbalance Service that we 
require as our ancillary service has a bandwidth appropriate for load 
variations and should have a price for exceeding the bandwidth that is 
appropriate for excessive load variations. Although NIMO states 
correctly that, where two control areas are involved, there can also be 
a mismatch between energy scheduled and energy generated, NIMO has not 
explained why this mismatch should have the same bandwidth and price as 
our Energy Imbalance Service. Indeed, we believe it should not.
    A generator should be able to deliver its scheduled hourly energy 
with precision. If we were to allow the generator to deviate from its 
schedule by 1.5 percent without penalty, as long as it returned the 
energy in kind at another time, this would discourage good generator 
operating practice. A generation supplier could intentionally generate 
less power when its generating cost is high and make it up when its 
cost is lower if the second type of mismatch is included in our Energy 
Imbalance Service. Instead, a generator will have an interconnection 
agreement with its

[[Page 12307]]

transmission provider or control area operator, and we expect that this 
agreement will specify the requirements for the generator to meet its 
schedule, and for any consequence for persistent failure to meet its 
schedule. This agreement will be tailored to the parties' specific 
standards and circumstances, and, although such arrangements must not 
be unduly preferential or discriminatory (e.g., must be comparable for 
all wholesale sellers, including the transmission provider's own 
wholesale sales), we prefer not to set these standards generically for 
all parties.<SUP>173
---------------------------------------------------------------------------

    \173\ Many provisions regarding the reliable operation and 
performance of both generation and load will be included in supply 
interconnection agreements and transmission customer service 
agreements. The fact that we have designated six services as 
necessary to prevent undue discrimination in transmission service 
should not be interpreted as our having set out a complete set of 
interconnected operations services and conditions necessary for 
reliable and orderly bulk power system management.
---------------------------------------------------------------------------

    We disagree with NCMPA's argument regarding an exemption from 
Energy Imbalance Service when the control area operator controls the 
generating resource. As discussed above and in the Final Rule, energy 
imbalance results from a mismatch between a scheduled receipt and 
actual load in the control area of the transmission provider. Energy 
imbalance can occur if the actual load differs from the scheduled 
receipt regardless of who controls the generating resource.
    As specified in the Final Rule, to ensure the reliability of the 
power system, a transmission customer is obligated to obtain Energy 
Imbalance Service and Regulation and Frequency Response Service for its 
transactions. We clarify for NPPD that the transmission customer may 
not decline the transmission provider's offer of these ancillary 
services unless it demonstrates to the transmission provider that it 
has acquired the services from another source. This demonstration must 
show that the customer's alternative arrangement for ancillary services 
is adequate and consistent with Good Utility Practice. The transmission 
customer's service agreement should specify any alternative 
arrangements for the provision of these (or any other) ancillary 
services.
(2) Energy Imbalance Bandwidth
    As explained above, Schedule 4 (Energy Imbalance Service) of the 
tariff allows the transmission provider to charge a transmission 
customer serving load in its control area for taking an amount of 
energy in any hour that is 1.5 percent more or less than the amount of 
energy scheduled for that hour. In the pro forma tariff, the minimum 
amount of energy that can be assessed a charge in an hour is one 
megawatt-hour.

Rehearing Requests

    Several entities argue that this energy imbalance bandwidth is too 
narrow and should be increased.<SUP>174 APPA asserts that the narrow 
bandwidth imposes obligations on the transmission customer that the 
transmission provider does not impose on itself.<SUP>175 TAPS argues 
that the 1.5 percent bandwidth ``makes no sense because it simply 
imposes a penalty for existence as a small utility.'' Redding states 
that the 1.5 percent energy imbalance bandwidth is not appropriate for 
transmission to a small utility that does not operate a control area. 
In opposing the narrow bandwidth, TDU Systems notes that metering error 
is typically within a range of <plus-minus>2 percent. It further argues 
that it is impossible for smaller systems with low load factors, larger 
load swings, and the need to change the output quickly for a single 
unit to operate within the narrow bandwidth. Others assert that a too-
narrow bandwidth creates a burdensome level of billings unless schedule 
changes are permitted more frequently than hourly.<SUP>176 They fear 
that meeting the 1.5 percent bandwidth would require expensive dynamic 
scheduling.
---------------------------------------------------------------------------

    \174\ E.g., APPA, NRECA, Blue Ridge, Cooperative Power, Wabash, 
TDU Systems, Redding, TAPS.
    \175\ See also TDU Systems.
    \176\ E.g., NRECA, Blue Ridge, Cooperative Power, Wabash.
---------------------------------------------------------------------------

    Some entities recommend a particular alternative bandwidth.<SUP>177 
TDU Systems suggests a sliding scale as follows. There would be a 
bandwidth of <plus-minus>5 percent of scheduled energy for transactions 
of 500 MW or less, decreasing to <plus-minus>1.5 percent for 
transactions of 5,000 MW or more, with a minimum bandwidth of 
<plus-minus>5 MWh in all cases. Alternatively, TDU Systems says that 
network customers could be entitled to a bandwidth equal to their load 
ratio share of the amount (not percentage) of their transmission 
provider's inadvertent interchange, again subject to a minimum of 5 
MWh. TAPS recommends that the deviation bandwidth be changed to 6 
percent of the transmission customer's daily peak demand, with a 
minimum bandwidth of 4 MWh.
---------------------------------------------------------------------------

    \177\ E.g., TDU Systems, TAPS, NRECA, Wabash, Redding.
---------------------------------------------------------------------------

    NRECA proposes an alternative approach (previously set forth in its 
comments on the proposed rule): a customer's ``energy compensation 
balance'' should be determined for each hour based on the net energy 
deviation from the ``bandwidth base,'' which NRECA defines as the 
greater of (i) the customer's total on-line and available generator 
capacity associated with the generation dispatched, or (ii) the sum of 
a customer's maximum hourly demands at each of its recipient 
interfaces. NRECA states that its proposal sets forth separate 
compensation based on whether there is an overdelivery or an 
underdelivery outside a five percent bandwidth.
    Wabash argues that the Commission should use a deviation bandwidth 
based on a period other than a single hour; for example, use a known 
historical number, such as the maximum hourly load during the previous 
calendar year. Wabash states that if a larger bandwidth is not adopted, 
the Commission should permit a transmission customer that is purchasing 
spinning or supplemental operating reserves as an ancillary service to 
use those purchases as the basis for an expanded deviation bandwidth. 
In addition, Wabash asks the Commission to clarify that an imbalance 
resulting from a system emergency situation caused by loss or failure 
of facilities should be counted as ``inadvertent loads'' and repaid in 
like hours at mutually agreed times and pay-back amounts.
    Redding points out that the NERC (A2 Criterion) establishes a 
constant bandwidth for every hour of the year and should be used 
instead. For energy imbalances of less than 1.5 percent, Schedule 4 of 
the tariff allows the energy to be returned in kind within 30 days, 
after which payment must be made. Redding argues that the 30-day period 
should be deleted. Instead the Commission should follow current 
industry practice of allowing reasonable deviations to be carried 
forward into the next month so as to avoid an accounting nightmare. 
Finally, Redding argues that the bandwidth for network service should 
apply to the entire network load and not to a ``scheduled 
transaction.''
    Wisconsin Municipals asks the Commission to clarify that if parties 
have reached a settlement that establishes a wider band, the 
transmission provider may not use Order No. 888 to avoid this 
settlement obligation.
    TAPS argues that any charges for exceeding the bandwidth should be 
cost-based and compensation should be symmetrical for over-and under-
deliveries.<SUP>178 TAPS further argues that

[[Page 12308]]

the bandwidth should not be applied by transaction, and customers 
should not have to pay for imbalances caused by transmission provider 
dispatch mistakes.
---------------------------------------------------------------------------

    \178\ On the other hand, Wabash argues that pursuant to industry 
practice, overdeliveries should be treated differently than 
underdeliveries outside the deviation band. It adds that the rate 
for underdeliveries should be cost-based.
---------------------------------------------------------------------------

    TDU Systems states that public utilities should be placed on notice 
that they will not be permitted to collect 100 mills per kWh for energy 
supplied by a customer in excess of its schedules, as some have sought 
in tariffs already filed.

Commission Conclusion

    Energy Imbalance Service includes a bandwidth to promote good 
scheduling practices by transmission customers. It is important that 
the implementation of each scheduled transaction not overly burden 
others.
    We do not agree with APPA that the bandwidth imposes an obligation 
on the transmission customer that the transmission provider does not 
impose on itself. The Final Rule treats all wholesale customers 
comparably. The transmission provider must also use its pro forma 
tariff and apply the same bandwidth for sales to its wholesale 
customers.
    Many commenters assert that the energy imbalance bandwidth of 
<plus-minus>1.5 percent is too narrow and is difficult to meet for 
small utilities. Several propose an alternative bandwidth or a larger 
minimum deviation. We believe that the bandwidth included in the Final 
Rule pro forma tariff is consistent with what the industry has been 
using as a standard and is as close to an industry standard as anyone 
can set at this time. However, we will set a larger minimum deviation 
to meet the needs of small customers. The minimum energy imbalance is 
now two megawatt-hours per hour (2 MW minimum in the pro forma tariff). 
This adequately addresses the concerns raised by small utilities 
because they may exceed the bandwidth without exceeding this minimum. 
For example, a transmission customer that transfers less than 133 MW 
(1.5 percent of 133 MW is 2 MW, the minimum energy imbalance) has a 
larger percentage bandwidth than <plus-minus>1.5 percent. The bandwidth 
set forth in the pro forma tariff provides a needed incentive for a 
transmission customer to deliver an amount of energy each hour that is 
reasonably close to the amount scheduled, while at the same time 
recognizing the needs of small utilities. To help customers with the 
difficulty of forecasting loads far in advance of the hour, the Final 
Rule pro forma tariff permits schedule changes up to twenty minutes 
before the hour at no charge. By updating its schedule before the hour 
begins, a transmission customer should be able to reduce or avoid 
energy imbalance and associated charges. However, we will allow the 
transmitting utility and the customer to negotiate and file another 
bandwidth more flexible to the customer, subject to a requirement that 
the same bandwidth be made available on a not unduly discriminatory 
basis.
    We disagree with Wabash's request to require a transmission 
provider to expand its energy imbalance bandwidth for a transmission 
customer purchasing spinning and supplemental reserves. Unlike Energy 
Imbalance Service, which treats deviations between scheduled and actual 
hourly energy deliveries, spinning and supplemental reserves provide 
generating capacity that responds to contingency situations (e.g., loss 
or failure of facilities). Order No. 888 requires a transmission 
customer to obtain these operating reserve ancillary services for its 
transactions. Therefore, Wabash is simply requesting a larger energy 
imbalance bandwidth. We have selected the bandwidth to promote good 
scheduling practices by transmission customers. A larger bandwidth may 
introduce poor operating practices that could affect the reliability of 
the system. If the Energy Imbalance Service bandwidth were larger, 
energy supplied within this expanded bandwidth could be provided from 
reserve capacity. Some reserve capacity may not then be available when 
needed for system reliability. However, as stated in the Final Rule, we 
will allow a transmission provider to assemble packages of ancillary 
services (not bundled with basic transmission service) that can be 
offered at rates that are less than the total of individual charges for 
the services if purchased separately.<SUP>179
---------------------------------------------------------------------------

    \179\ FERC Stats. & Regs. at 31,719; mimeo at 246.
---------------------------------------------------------------------------

    In response to Wabash's other concern, we believe that emergency 
situations caused by loss or failure of facilities should be addressed 
in the transmission customer's service agreement (or the generation 
supplier's separate interconnection agreement) and not as part of 
Energy Imbalance Service.
    In response to Redding's statement that the NERC (A2 criterion) 
establishes a constant bandwidth for imbalances, we note that NERC has 
set a standard for a kind of deviation that is different from our 
Energy Imbalance Service. NERC's bandwidth is for inadvertent 
interchange between a control area and all other control areas. Redding 
has presented no reason that our Energy Imbalance Service bandwidth 
should be the same as NERC's inadvertent interchange bandwidth. 
Regarding its concern about the in-kind repayment period, we note that 
Schedule 4 does not always require a 30-day period for in-kind 
repayment of energy imbalances; it also permits a term that the 
transmission provider consistently follows and is generally accepted in 
the region. In addition, we clarify that the bandwidth for network 
service applies to the entire network load.
    With respect to Wisconsin Municipals' request, we clarify that the 
Final Rule does not require parties to a contract that went into effect 
prior to July 9, 1996 to stop using a wider bandwidth established by 
settlement. However, service provided pursuant to a settlement that was 
expressly approved subject to the outcome of Order No. 888 on non-rate 
terms and conditions must be revised in the subsequent compliance 
filing to reflect the language contained in the pro forma 
tariff.<SUP>180 Subsequent to the compliance tariff filing, public 
utilities are free to file under section 205 to revise the tariffs 
(e.g., to reflect various settlement provisions) and customers are free 
to pursue changes under section 206.<SUP>181
---------------------------------------------------------------------------

    \180\ See Order on Non-Rate Terms and Conditions, 77 FERC para. 
61,144 at 61,538 (1996). The Commission explained:
    Order No. 888 required all tariff compliance filings to contain 
non-rate terms and conditions identical to the pro forma tariff, 
with a limited exception for regional practices, and with four 
attachments where the utility could propose specific inserts.
    \181\ FERC Stats. & Regs. at 31,770 n.514; mimeo at 399 n.514.
---------------------------------------------------------------------------

    In response to arguments regarding the price of Energy Imbalance 
Service, we note that the Final Rule intentionally does not provide 
detailed pricing requirements. We require the transmission provider to 
determine and apply to the Commission for appropriate rates for Energy 
Imbalance Service as part of its transmission tariff. Transmission 
customers may address any disagreements with a specific charge in the 
company's transmission rate case.
2. Ancillary Services Obligations
    In the Final Rule, the Commission distinguished two groups or 
categories of ancillary services: (1) services that the transmission 
provider is required to provide to all of its basic transmission 
customers under the tariff, and (2) services that the transmission 
provider is required to offer to provide only to transmission customers 
serving load in the provider's control area. The Commission required a 
transmission provider that operates a control area to provide the first 
group of ancillary services and the transmission customer

[[Page 12309]]

to purchase these services from the transmission provider. The 
Commission required a transmission provider to offer to provide the 
ancillary services in the second group to transmission customers 
serving load in the transmission provider's control area. The 
Commission required the transmission customer serving load in the 
transmission provider's area to acquire these services, but allowed the 
transmission customer to do so from the transmission provider, a third 
party or self-supply.
    If the transmission provider is a public utility providing basic 
transmission service, but is not a control area operator, the 
Commission allowed the transmission provider to fulfill its obligation 
to provide, or offer to provide, ancillary services by acting as the 
customer's agent. In this case, if the control area operator is a 
public utility, the Commission required the control area operator to 
offer to provide all ancillary services to any transmission customer 
that takes transmission service over facilities in its control area 
whether or not the control area operator owns or controls the 
facilities used to provide the basic transmission service.
a. Obligation of a Control Area Utility

Rehearing Requests

    Carolina P&L asks the Commission to clarify that the transmission 
provider is not required to provide control area services to another 
utility operating a control area that simply chooses not to provide for 
its own control area obligations. It argues that this is not justified 
in a competitive bulk power market.
    Maine Public Service asserts that a transmission provider that is 
not a NERC-recognized control area can provide ancillary services from 
its own facilities. It asks that the Commission clarify that this is 
permissible. At a minimum, Maine Public Service states that the 
Commission must allow transmission providers on a case-by-case basis to 
establish that they provide ancillary services even if they are not 
NERC-recognized control areas or do not satisfy the Commission's 
definition (citing the initial decision in Maine Public Service 
Company, 74 FERC para. 63,011 (1996)).
    Similarly, California DWR states that it has been operating since 
1983 as a quasi-control area, self-providing most, if not all, of the 
ancillary services it uses. It also notes that it provides such 
services to its utility transmission providers. California DWR argues 
that it is entitled to appropriate compensation for all ancillary 
services that it provides to its transmission providers or other 
parties.

Commission Conclusion

    In response to Carolina P&L, we clarify that the Final Rule does 
not require a control area operator to provide control area services 
within another control area.
    Except for the ancillary service called Scheduling, System Control 
and Dispatch,<SUP>182 the Final Rule does not preclude a transmission 
provider that is not a control area operator from offering ancillary 
services to its transmission customers.
---------------------------------------------------------------------------

    \182\ As NERC and others pointed out in their comments on the 
proposed rule, this service can be provided only by the operator of 
the control area in which the transmission facilities used are 
located. FERC Stats. & Regs. at 31,716; mimeo at 238.
---------------------------------------------------------------------------

    Order No. 888 requires that a transmission customer obtain or 
provide ancillary services for its transactions. If a transmission 
customer can self-supply a portion of its requirement for ancillary 
services (other than Scheduling, System Control, and Dispatch Service), 
it should pay a reduced charge for these services. As with the 
transmission provider, a third party may offer ancillary services 
voluntarily to other customers if technology permits. However, simply 
supplying some duplicative ancillary services (e.g., providing reactive 
power at low load periods or providing it at a location where it is not 
needed) in ways that do not reduce the ancillary services costs of the 
transmission provider or that are not coordinated with the control area 
operator does not qualify for a reduced charge. The transmission 
customer must make separate arrangements with the transmission provider 
or control area operator to supply its own ancillary services and 
specify such arrangements in its service agreement.
b. Obligation to Provide Dynamic Scheduling
    Dynamic scheduling electronically moves a generation resource or 
load from the control area in which it is physically located to a new 
control area. In the Final Rule, the Commission concluded that it would 
not require the transmission provider to offer Dynamic Scheduling 
Service to a transmission customer, although a transmission provider 
may do so voluntarily. If the customer wants to purchase this service 
from a third party, the Commission stated that the transmission 
provider should make a good faith effort to accommodate the necessary 
arrangements between the customer and the third party for metering and 
communication facilities.

Rehearing Requests

    AMP-Ohio asks that the Commission clarify that the transmission 
provider is required to provide dynamic scheduling ``to the extent a 
transmission customer needs and is willing to pay for reasonably priced 
dynamic scheduling in order to support its operations, including in 
order to integrate its loads and resources located in more than one 
control area.'' Wisconsin Municipals also asks the Commission to 
clarify that dynamic scheduling must be provided if technically 
feasible and permitted by regional reliability practices.
    Wisconsin Municipals further asks that the Commission clarify that 
if the transmission provider has agreed to provide dynamic scheduling 
in a settlement, it may not use its Order No. 888 implementation filing 
to void this obligation.
    EEI asks that the Commission clarify the residual obligations of a 
control area utility to an entity that electronically leaves the 
control area via dynamic scheduling.

Commission Conclusion

    In response to Amp-Ohio and Wisconsin Municipals, we note that 
dynamic scheduling is not a required ancillary service in Order No. 
888, and we do not require a transmission provider to offer this 
service. However, nothing in the Final Rule precludes a transmission 
provider from offering it as a separate service. Furthermore, offering 
dynamic scheduling to integrate loads and resources in more than one 
control area is also not required.
    Wisconsin Municipals' argument with respect to prior settlements 
has been previously addressed in Section IV.D.1.c.(2) (Energy Imbalance 
Service).
    We clarify for EEI that, once dynamic scheduling is arranged, each 
of the two control areas has ancillary service responsibilities under 
the Rule. The reactive power obligations of the original control area 
remain and cannot be completely supplied by distant sources. Order No. 
888 requires, in the case of dynamic scheduling, both control areas to 
provide the first two ancillary services in their respective control 
areas, that is, (1) Scheduling, System Control, and Dispatch Service 
and (2) Reactive Supply and Voltage Control from Generation Sources 
Service, and the new control area to offer the remaining ancillary 
services to the dynamically scheduled entity. In addition, the actual 
energy transfers between the two control areas will require basic 
transmission service. We

[[Page 12310]]

expect that any additional obligations of a control area operator to an 
entity that electronically leaves the control area via dynamic 
scheduling, such as backup procedures for the failure of telemetering 
equipment, will be set out in the transmission customer's service 
agreement.
c. Obligation As Agent

Rehearing Requests

    A transmission provider must act as an agent to help the customer 
acquire ancillary services if the transmission provider cannot provide 
them itself. NRECA asks whether a non-public utility may collect a 
reasonable fee for its agency services in fulfilling its reciprocity 
requirement.

Commission Conclusion

    While the Final Rule does not allow a public utility transmission 
provider acting as an ancillary services agent to collect a fee for its 
agency service, we do not have similar authority to deny a non-public 
utility the opportunity to charge a fee for providing an agency 
service. However, to the extent a non-public utility seeks to collect 
an agency fee from a public utility, it must meet our comparability 
requirements and charge a comparable fee to its own wholesale merchant 
function.
3. Miscellaneous Ancillary Services Issues
a. Transmission Provider as Ancillary Services Merchant

Rehearing Requests

    Allegheny asserts that the sale of power in connection with 
ancillary services would make the transmission provider a wholesale 
merchant under the Commission's standards of conduct (citing section 
37.3 of the Commission's Regulations). Allegheny asks that the 
Commission clarify that a transmission provider's employee responsible 
for providing ancillary services is not engaged in a wholesale merchant 
service that would trigger the functional separation requirement.

Commission Conclusion

    We clarify that the transmission provider's sale of ancillary 
services associated with its provision of basic transmission service is 
not a wholesale merchant function for purposes of Order No. 889. This 
is because the provision of ancillary services is essential for 
providing transmission service. However, the sale of ancillary services 
not associated with the transmission provider's provision of basic 
transmission service is a wholesale function for purposes of Order No. 
889. Thus, if an employee is marketing an ancillary service independent 
of the transmission provider's obligations to provide transmission 
service, i.e., as a third party to another transmission provider's 
basic transmission service customer, the employee would be providing a 
wholesale merchant function and the Order No. 889 Standards of Conduct 
apply.
b. QF Receipt of Ancillary Services

Rehearing Requests

    North Jersey argues that the Commission did not engage in reasoned 
decisionmaking in ruling that Real Power Loss Service is not an 
ancillary service. It asserts that this service must be provided by the 
transmission provider. North Jersey further argues that, because the 
Commission describes the furnishing of real power loss as a sale of 
power, this could prevent a PURPA qualifying facility (QF) from being a 
transmission service customer. North Jersey states that a QF faces 
power purchase and resell restrictions under the Commission's 
regulations. North Jersey asks that the Commission find that receipt of 
Real Power Loss Service from a third party to complete a transmission 
transaction is not a purchase and resale of power. In addition, North 
Jersey requests that the Commission clarify that receipt of ancillary 
services by a QF does not constitute a purchase and resale of electric 
power that would jeopardize its status as a QF (clarification also 
requested in ER95-791-000).\183\
---------------------------------------------------------------------------

    \183\ In Docket No. ER95-791 the Commission ruled that this 
issue was not part of the hearing and that North Jersey should file 
for a declaratory order to resolve the matter.
---------------------------------------------------------------------------

Commission Conclusion

    The Commission disagrees with North Jersey's assertion that Real 
Power Loss Service should be an ancillary service that must be provided 
by the transmission provider. As stated in the Final Rule, it is not 
necessary for the transmission provider to supply Real Power Loss 
Service to effect a transmission service transaction. Although the 
transmission customer is responsible for losses associated with its 
transmission service, supply of losses is purely a generation service 
that can be (1) self supplied; (2) purchased from the transmission 
provider, if it offers this service; or (3) purchased from a third 
party.
    We clarify that a QF arrangement for receipt of Real Power Loss 
Service or ancillary services from the transmission provider or a third 
party for the purpose of completing a transmission transaction is not a 
sale-for-resale of power by a QF transmission customer that would 
violate our QF rules.
c. Pricing of Ancillary Services
    In the Final Rule, the Commission concluded that it would consider 
ancillary services rate proposals on a case-by-case basis and offered 
general guidance on ancillary services pricing principles.\184\
---------------------------------------------------------------------------

    \184\ FERC Stats. & Regs. at 31,720-21; mimeo at 250-52.
---------------------------------------------------------------------------

Rehearing Requests

    NRECA and TDU Systems argue that there should be truth in 
transmission pricing so that the rate is clearly identified as 
including or excluding ancillary services.
    AEP asserts that if a purchaser of ancillary services has 
alternative suppliers of these services, then either the transmission 
provider should not be required to provide those services or it should 
be able to charge market rates for them. Otherwise, according to AEP, 
the market is skewed in favor of the customer.
    Illinois Power argues that if a transmitting utility demonstrates 
that it incurs incremental costs from its obligation to offer to 
provide the required ancillary services, it should be permitted to 
recover such costs through an adjustment to base transmission rates.

Commission Conclusion

    The Final Rule requires unbundling of individual ancillary services 
from basic transmission service. We point out to NRECA and TDU Systems 
that the transmission provider must post and update prices for basic 
transmission and each ancillary service on its OASIS. As discussed 
below in Section IV.G.1.h. (Discounts), the Commission is revising its 
policy regarding the discounting of the price of transmission services. 
There, we establish three principal requirements for discounting basic 
transmission service.\185\ We clarify here that these principal 
requirements apply to discounts for ancillary services provided by the 
transmission provider in support of its provision of basic transmission 
service. However, because ancillary services are generally not path-

[[Page 12311]]

specific, 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. In addition, if a transmission provider 
offers any rate or packaged ancillary service discounts, it must post 
them on its OASIS and make them available to affiliates and non-
affiliates on a basis that is not unduly discriminatory. In this 
manner, any discounting of ancillary service prices is visible to all 
market participants. We will require that, as soon as practicable, any 
``negotiation'' of discounts between a transmission provider and 
potential transmission (and ancillary) service customers should take 
place on the OASIS.\186\
---------------------------------------------------------------------------

    \185\ In brief, these are that (1) any offer of a discount made 
by the transmission provider must be announced to all potential 
customers solely by posting on the OASIS, (2) any customer-initiated 
requests for discounts (including requests for one's own use or for 
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. In addition to these three principal 
requirements, we also require that a discount agreed upon for a path 
must be extended to certain other paths described in Section 
IV.G.1.h.
    \186\ ''Negotiation'' would only take place if the transmission 
provider or potential customer seeks prices below the ceiling prices 
set forth in the tariff.
---------------------------------------------------------------------------

    We continue to require a transmission provider to provide or offer 
to provide the six ancillary services, even if the transmission 
customer has some alternative suppliers. We distinguished these six 
services from others (e.g., Real Power Loss Services) for which many 
suppliers are typically available. In some cases, only the transmission 
provider can provide the ancillary service; in other cases too few 
providers are available to create a market for these services. Further, 
we were persuaded by the comments of NERC and others that these 
services are essential for reliability; if a customer must obtain these 
services to obtain transmission service there must be a default 
provider of these services. However, market-based rates for some of the 
ancillary services may be appropriate if the seller lacks market power 
for such services. Market power issues regarding ancillary services 
have to be addressed before market-based rates for ancillary services 
can be approved, as requested by AEP. We will consider market-based 
rates for ancillary services on a case-by-case basis.
    In reply to Illinois Power, we agree that the transmission provider 
may incur incremental costs from its obligation to offer to provide 
ancillary services. We believe, however, these costs should be included 
in the price for those services. Order No. 888 requires the 
transmission provider to unbundle the cost of ancillary services from 
the base transmission rate. A rebundling of these costs with the base 
transmission rate, as Illinois Power requests, would not satisfy the 
unbundling requirement.

E. Real-Time Information Networks

    In the Final Rule, the Commission concluded that in order to remedy 
undue discrimination in the provision of transmission services it is 
necessary to have non-discriminatory access to transmission 
information, and that an electronic information system and standards of 
conduct are necessary to meet this objective.\187\ Therefore, in 
conjunction with the Final Rule, the Commission issued a final rule 
adding a new Part 37 that requires the creation of a basic OASIS and 
standards of conduct.
---------------------------------------------------------------------------

    \187\ FERC Stats. & Regs. at 31, 722; mimeo at 255-56.
---------------------------------------------------------------------------

Rehearing Requests

    Rehearing requests raising arguments with respect to specific 
aspects of OASIS and standards of conduct are addressed in Order No. 
889-A, issued concurrently with this order.

F. Coordination Arrangements: Power Pools, Public Utility Holding 
Companies, Bilateral Coordination Arrangements, and Independent System 
Operators

    In the Final Rule, the Commission explained that its requirement 
for non-discriminatory transmission access and pricing by public 
utilities, and its specific requirement that public utilities unbundle 
their transmission rates and take transmission service under their own 
tariffs, apply to all public utilities' wholesale sales and purchases 
of electric energy, including coordination transactions.\188\ While the 
Commission ``grandfathered'' certain existing requirements agreements 
and non-economy energy coordination agreements, it also determined that 
certain existing wholesale coordination arrangements and agreements 
must be modified to ensure that they are not unduly discriminatory. The 
Commission then discussed (as set forth further below) how and when 
various types of coordination agreements will need to be modified, and 
when public utility parties to coordination agreements must begin to 
trade power under those agreements using transmission service obtained 
under the same open access transmission tariff available to non-
parties.
---------------------------------------------------------------------------

    \188\ FERC Stats. & Regs. at 31,725-27; mimeo at 266-70.
---------------------------------------------------------------------------

    The Commission explained that it was addressing four broad 
categories of coordination arrangements and accompanying agreements: 
``tight'' power pools, ``loose'' power pools, public utility holding 
company arrangements, and bilateral coordination arrangements.
    In addition, the Commission explained that ISOs may prove to be an 
effective means for accomplishing comparable access and, accordingly, 
provided guidance on minimum ISO characteristics.
1. Tight Power Pools
    The Commission required public utilities that are members of a 
tight pool to file, within 60 days of publication of the Final Rule in 
the Federal Register, either: (1) an individual Final Rule pro forma 
tariff; or (2) a joint pool-wide Final Rule pro forma tariff.\189\ 
However, the Commission required them to file a joint pool-wide Final 
Rule pro forma tariff no later than December 31, 1996, and to begin to 
take service under that tariff for all pool transactions no later than 
December 31, 1996.\190\ The Commission also required the public utility 
members of tight pools to file reformed power pooling agreements no 
later than December 31, 1996 if the agreements contain provisions that 
are unduly discriminatory or preferential.
---------------------------------------------------------------------------

    \189\ FERC Stats. & Regs. at 31,727-28; mimeo at 270-72.
    \190\ By notice issued September 27, 1996, the Commission 
extended the date by which public utilities that are members of 
tight power pools must take service under joint pool-wide open 
access transmission tariffs from no later than December 31, 1996 to 
60 days after the filing of their joint pool-wide section 206 
compliance tariff.
---------------------------------------------------------------------------

    If a reformed power pooling agreement allows members to make 
transmission commitments or contributions in exchange for discounted 
transmission rates, the Commission indicated that the pool may file a 
transmission tariff that contains an access fee (or file a higher 
transmission rate) for non-transmission owning members or non-members, 
justified solely on the basis of transmission-related costs.

Rehearing Requests

    Consumers Power asks the Commission to clarify that Order No. 888 
does not preclude the Michigan Electric Coordinated Systems (MECS) from 
being in compliance by removing all transmission functions from pool 
control and allowing pool members or the pool to take transmission 
service from transmission-owning pool members under their open access 
tariffs. It asserts that this would be an interim placeholder 
alternative while retail deliberations continue in Michigan. 
Furthermore, as one of the two members of MECS, Consumers Power 
indicates that it would be willing to consider further modifications 
that would liberalize membership criteria during the transition period 
if the Commission otherwise clarifies that the MECS Pool is in 
compliance with Order No. 888.

[[Page 12312]]

    NY Municipals request that the Commission clarify that, 
particularly if generation services are to be provided at market-based 
rates, monopoly transmission services must continue to be provided at 
cost-based rates (raised in connection with the NYPP). They also ask 
that the Commission clarify that joint pool-wide tariffs must 
incorporate transmission rates that are uniform (non-pancaked) and 
strictly based on the embedded costs of the transmission facilities and 
related transmission expenses. Moreover, NY Municipals argue that 
transmission owners should receive a credit based on the depreciated 
costs of their transmission facilities.
    TAPS also asks the Commission to clarify that pool-wide and system-
wide tariffs must contain non-pancaked rates.

Commission Conclusion

    While Consumers Power's proposal to remove transmission functions 
from pool control, if implemented in a non-discriminatory fashion, 
would satisfy the comparability requirements of Order No. 888, the 
Commission encourages Consumers Power to pursue a pool-wide 
tariff.\191\
---------------------------------------------------------------------------

    \191\ It is not clear from the rehearing request exactly how the 
current members of MECS are proposing to remove all transmission 
functions from pool control and to take transmission service under 
their individual open access tariffs. For example, this may preclude 
the continuation of joint economic dispatch of generating facilities 
belonging to Consumer Power and Detroit Edison, which the rehearing 
request appears to assume would continue. However, the Commission 
will address the adequacy of any such proposal in the context of the 
appropriate compliance filings.
---------------------------------------------------------------------------

    NY Municipal Utilities' concern that rates for transmission service 
will not be priced at cost-based rates is ill-founded. While Order No. 
888 does not establish any specific pricing methodology for tariff 
transmission service, the Commission expects all transmission rate 
proposals filed on compliance to be cost based and to meet the standard 
for conforming proposals set out in the Commission's Transmission 
Pricing Policy Statement. (See 18 CFR 2.22).
    Regarding NY Municipal Utilities' and TAPS's requests for a uniform 
tariff with non-pancaked rates, Order No. 888 does not require a non-
pancaked rate structure unless a non-pancaked rate structure is 
available to pool members. Although the Commission has encouraged the 
industry to reform transmission pricing, the Commission's current 
policy does not mandate a specific transmission rate structure.
    With regard to NY Municipal Utilities' concern about market-based 
rates for generation, public utility owners of existing NYPP generation 
are not eligible to charge market-based power sales rates absent 
Commission approval. Order No. 888 allows market-based rates only if 
the seller in a case-specific filing demonstrates it meets the 
Commission's well-established criteria of showing that it and its 
affiliates do not have or have adequately mitigated transmission market 
power and generation market power, that there are no other barriers to 
entry, and there is no evidence of affiliate abuse or reciprocal 
dealing. With regard to requests to make market-based sales from new 
generation, the seller does not have to submit evidence of generation 
market power in long-run bulk power markets (subject to challenge where 
specific evidence can be presented); <SUP>192 however, for sales from 
existing generation at market-based rates, the applicant must 
demonstrate that it lacks, or has fully mitigated, generation market 
power.<SUP>193
---------------------------------------------------------------------------

    \192\ FERC Stats. & Regs. at 31,657; mimeo at 64-65; section 
35.27.
    \193\ FERC Stats. & Regs. at 31,660; mimeo at 73-74.
---------------------------------------------------------------------------

    In response to NY Municipals' request that transmission owners that 
contribute transmission facilities to a power pool should receive a 
rate credit based on the depreciated costs of those transmission 
facilities, we agree that this is one possible way of reflecting a pool 
member's contributions or commitments of transmission facilities. 
However, NY Municipals has provided no rationale as to why we should 
limit the broader approach we adopted in Order No. 888 to this single 
mechanism.<SUP>194
---------------------------------------------------------------------------

    \194\ See FERC Stats. & Regs. at 31,727-28; mimeo at 271-72.
---------------------------------------------------------------------------

2. Loose Pools
    In the Final Rule, the Commission found that public utilities 
within a loose pool must file, within 60 days of publication of the 
Final Rule in the Federal Register, either: (1) an individual Final 
Rule pro forma tariff; or (2) a pool-wide Final Rule pro forma 
tariff.<SUP>195 However, the Commission required that they file a joint 
pool-wide Final Rule pro forma tariff no later than December 31, 1996, 
and begin to take service under that tariff for all pool transactions 
no later than December 31, 1996. <SUP>196 The Commission also required 
that the public utility members of loose pools file reformed power 
pooling agreements no later than December 31, 1996 if the agreements 
contain provisions that are unduly discriminatory or preferential. They 
also must file a joint pool-wide tariff no later than December 31, 
1996.
---------------------------------------------------------------------------

    \195\ FERC Stats. & Regs. at 31,728; mimeo at 272-74.
    \196\ By notice issued September 27, 1996, the Commission 
extended the date by which public utility members of loose power 
pools must take service under joint pool-wide open access 
transmission pro forma tariffs from no later than December 31, 1996 
to 60 days after the filing of their joint pool-wide section 206 
compliance tariff.
---------------------------------------------------------------------------

    If a reformed pooling agreement allows members to make transmission 
commitments or contributions in exchange for discounted transmission 
rates, the Commission determined that the pool may file a transmission 
tariff that contains an access fee (or a higher transmission rate) for 
non-transmission owning members or non-members, justified solely on the 
basis of transmission-related costs.

Rehearing Requests

    Union Electric asserts that the definition of loose pools is so 
vague that many public utilities, regional organizations and multi-
lateral arrangements, which are not actually pools, may incorrectly be 
deemed loose pools by third parties. Thus, Union Electric asks the 
Commission to clarify that members or parties to multi-lateral 
arrangements only need to offer transmission services pursuant to their 
own individual company tariffs.
    EEI asks the Commission to clarify the nature of the tariffs that 
loose pools may file to comply with the Rule to ensure that the members 
are not required to file tariffs for services that they do not now 
provide. EEI also requests that, where members of loose pools currently 
provide transmission services to each other, they may continue to 
provide such services to each other under each member's individual pro 
forma tariff in lieu of a pool-wide tariff (provided that those 
services are made available to all eligible entities on a non-
discriminatory basis). Similarly, Montana Power argues that members of 
loose pools should be allowed to meet comparability by filing 
individual open access tariffs, without having to file a pool-wide 
tariff.<SUP>197
---------------------------------------------------------------------------

    \197\ See also Public Service Co of CO.
---------------------------------------------------------------------------

    Public Service Co of CO asserts that the primary purpose of the 
Inland Power Pool is to provide for reserve sharing during emergency 
conditions, although the pool agreement also allows for economy 
transactions. It argues that another way to comply with the Rule should 
be to eliminate the economy energy schedule of the Inland Power Pool 
Agreement. Moreover, Public Service Co of CO argues that given the 
number of non-jurisdictional entities within the Inland Power Pool, it 
may be impossible to agree on a pool-wide tariff. El Paso adds that 
Inland Power Pool should not be treated as a loose

[[Page 12313]]

pool because it functions as a reserve sharing mechanism and not as a 
pool.
    Utilities For Improved Transition asks the Commission to clarify 
that pool members or members of other entities do not have to provide 
more transmission services than they already provide on a voluntary 
basis to each other. It contends that there is no record to support a 
broader obligation and would cause massive disruption and the 
disintegration of many existing pools. Utilities For Improved 
Transition maintains that pools should have substantial leeway to 
develop arrangements reflecting their diverse memberships and the 
diverse contributions made.
    VEPCO seeks clarification whether the Commission intended to impose 
the single-system tariff requirement only with respect to multilateral 
agreements that provide for system-wide transmission rates for the 
parties to the agreements.
    TAPS asks the Commission to clarify that section 35.28(c)(3) 
includes all pools and all holding company systems, as well as any 
multi-lateral agreement so long as the multi-lateral agreement 
explicitly or implicitly addresses transmission (e.g., by providing for 
a transaction without assessing transmission costs in connection with 
that transaction).

Commission Conclusion

    In response to parties seeking clarification of the definition of a 
loose pool, the Commission clarifies that a loose pool is any 
multilateral arrangement, other than a tight power pool or a holding 
company arrangement, that explicitly or implicitly contains discounted 
and/or special transmission arrangements, that is, rates, terms, or 
conditions. The Commission requires public utilities that are members 
of a loose pool to either (1) reform their pooling arrangements in 
accordance with Order No. 888 or (2) excise all discounted and/or 
special arrangements transmission service from the pooling arrangement. 
That is, in the latter case the members could continue to provide other 
services (e.g., generation), but would cease to be a loose pool for 
purposes of Order No. 888.
    The primary goal of Order No. 888's requirements for pooling 
arrangements, including ``loose'' pools, is to ensure comparability 
regarding transmission services that are offered on a pool-wide basis. 
We believe comparability for loose pools can be achieved if pooling 
agreements are modified: (1) to allow open membership and (2) to make 
the transmission service in the loose pool agreement available to 
others. While the Commission encourages pool-wide transmission tariffs 
that offer the full range of transmission services included in the pro 
forma tariff, we will not require, under the comparability principles 
of Order No. 888, that pool members offer to third parties transmission 
services that they do not provide to themselves on a pool-wide basis. 
For example, if existing loose pool members do not offer network 
services to each other, they do not have to expand the pool services to 
offer network services to themselves or any third parties. 
Additionally, we do not find it to be unduly discriminatory to provide 
some pool-wide transmission services to members under a pooling 
agreement and to provide other transmission services to members under 
the individual tariff of each member, as long as members and non-
members have access to the same transmission services on a comparable 
basis and pay the same or a comparable rate for transmission.<SUP>198
---------------------------------------------------------------------------

    \198\ See FERC Stats. & Regs. at 31,728; mimeo at 273-74.
---------------------------------------------------------------------------

    The Commission notes that the Inland Power Pool agreement provides 
for non-firm transmission service (Service Schedule D) for emergency 
service, scheduled outage service, and economy energy service. The 
Inland Power Pool agreement provides members preferential transmission 
rates for deliveries of emergency service, i.e., members will provide 
free non-firm transmission service at a higher priority than any other 
non-firm transactions. Such preferential service is not available to 
non-members. We consider any rates, terms or conditions of transmission 
service that favor members over non-members to be unduly discriminatory 
and preferential, whether embodied explicitly or implicitly in a loose 
pooling agreement. Pool members can either amend the agreement to 
provide comparable services to others and open the pool to new members, 
or amend the agreement to eliminate any preferential transmission 
availability and/or pricing.
    In response to TAPS, the Commission agrees that Section 35.28(c)(3) 
applies to any pool, holding company system or multi-lateral agreement 
that contains explicit or implicit transmission rates, terms, or 
conditions.<SUP>199 For example, if a utility offers transmission 
without charge as part of such an agreement, it must offer transmission 
to all parties requesting a similar service either without charge or at 
an access fee or other transmission rate that comparably reflects 
transmission-related costs borne by members of the agreement.<SUP>200
---------------------------------------------------------------------------

    \199\ See FERC Stats. & Regs. at 31,726; mimeo at 268-69 (filing 
of open access tariffs by public utility pool members is not enough 
to cure undue discrimination in transmission if those entities can 
continue to trade with a selective group within a power pool; the 
same holds true for certain bilateral arrangements allowing 
preferential pricing or access) and FERC Stats. & Regs. at 31,727-
28; mimeo at 270-272 (tight and loose pools must file joint pool-
wide tariffs).
    \200\ See FERC Stats. & Regs. at 31,730; mimeo at 278.
---------------------------------------------------------------------------

3. Public Utility Holding Companies
    In the Final Rule, the Commission required that holding company 
public utility members, with the exception of the Central and South 
West (CSW) System, file a single system-wide Final Rule pro forma 
tariff permitting transmission service across the entire holding 
company system at a single price within 60 days of publication of the 
Final Rule in the Federal Register.<SUP>201
---------------------------------------------------------------------------

    \201\ FERC Stats. & Regs. at 31,728-29; mimeo at 274-77.
---------------------------------------------------------------------------

    With respect to CSW, the Commission directed the public utility 
subsidiaries of CSW to consult with the Texas, Arkansas, Oklahoma and 
Louisiana Commissions and to file not later than December 31, 1996 a 
system tariff that will provide comparable service to all wholesale 
users on the CSW System, regardless of whether they take transmission 
service wholly within ERCOT or the SPP, or take transmission service 
between the reliability councils over the North and East 
Interconnections.
    The Commission gave public utilities that are members of holding 
companies an extension of the requirement to take service under the 
system tariff for wholesale trades between and among the public utility 
operating companies within the holding company system until December 
31, 1996--the same extension it granted to power pools.<SUP>202 In 
addition, the Commission indicated that it may be necessary for 
registered holding companies to reform their holding company 
equalization agreement to recognize the non-discriminatory terms and 
conditions of transmission service required under the Final Rule pro 
forma tariff.
---------------------------------------------------------------------------

    \202\ By notice issued September 27, 1996, the Commission 
extended the date by which public utilities that are members of 
holding companies must take service under their system-wide tariffs 
from December 31, 1996 to no later than March 1, 1997.
---------------------------------------------------------------------------

Rehearing Requests

    FL Com asks the Commission to clarify whether it intends to require 
operating company members of a registered holding company to charge 
each other the same wheeling charge to be charged to others even though 
others pay nothing for transmission construction. FL Com argues that 
such

[[Page 12314]]

a charge would be inconsistent with the Commission's traditional 
treatment of public utility holding companies as a single entity.
    AL Com asks the Commission to clarify that ``intra-holding company 
transactions in support of economic dispatch across a single integrated 
system should not be subjected to additional transmission charges, 
while transactions between operating companies for the benefit of 
wholesale customers not included within the definition of native load 
customer require distinct transmission charges.'' <SUP>203
---------------------------------------------------------------------------

    \203\ AL Com at 1-4.
---------------------------------------------------------------------------

    Southern asks the Commission to clarify that transactions between 
public utility operating subsidiaries within a holding company system 
for the benefit of native load customers fall within the network 
service for which they are assigned cost responsibility under the Final 
Rule tariff.
    AEP asserts that the Commission has provided no reason for 
requiring holding companies to use the pro forma tariff for intra-pool 
transactions. AEP asks the Commission to clarify whether the Rule 
applies to AEP. It asserts that the Preamble states that all members of 
holding company systems must use the pro forma tariff for intra-system 
transactions, but the regulatory text requires only a member of a 
public utility holding company ``arrangement or agreement that contains 
transmission rates, terms or conditions * * *.'' AEP explains that the 
AEP System Interconnection Agreement and Transmission Agreement do not 
contain transmission rates, terms or conditions and the members do not 
offer transmission service to one another.
    However, AEP argues that, if the Rule applies to AEP, Order No. 888 
contains no explanation of why or how a different intra-pool allocation 
of transmission costs than would result from the pro forma tariff 
prejudices transmission users. It asserts that (1) AEP's allocation has 
been subject to extensive review over the last few years, (2) AEP 
treats itself as a single system, not as a collection of individual 
members, (3) each member carries its fair share of transmission costs, 
and (4) compliance with the Commission's requirement would be onerous. 
If the Commission does not remove this requirement, AEP requests waiver 
of the requirement.
    Similarly, Allegheny Power asserts that its Power Supply Agreement 
(PSA) does not provide for ``wholesale trades.'' It argues that the PSA 
is immaterial to all transmission services, including intra-company 
exchanges. Because the PSA is an existing contract that the Final Rule 
does not propose to abrogate, Allegheny Power asserts that the PSA need 
not be reformed under the Final Rule. Allegheny states that it will 
provide new wholesale service to itself and others under its open 
access tariff which was accepted for filing on December 6, 1995 in 
Docket No. ER96-58.
    Union Electric assumes that the ``rule is intended solely to mean 
that a holding company system would use the network integration part of 
the tariff, for its intra-system `wholesale trades.' Indeed, if Union 
Electric and CIPS were required to take point-to-point service for 
their wholesale trades, they would be placed in an inferior and non-
comparable position vis-a-vis customers on the Ameren tariff who will 
be entitled to single-system transmission service for a single or 
postage-stamp charge.'' (Union Electric notes that Union Electric and 
CIPS are currently seeking approval to merge, with the combined 
facilities being operated as the Ameren System.)
    NU believes that Order No. 888 could be construed to require NU 
System Companies to charge each other as separate entities for 
transmission service in connection with intra-system cost allocations 
as if off-system wholesale sales had occurred. NU argues, however, that 
this is inconsistent with Commission precedent in treating the NU 
System Companies as a single integrated system and would give retail 
native load customers service inferior to that of wholesale native load 
(i.e., network) customers. NU further argues that it will result in 
duplicative transmission charges for energy flows between the NU System 
Companies. Moreover, NU asserts that viewing NU as a single system for 
establishing transmission rates, but as separate companies with respect 
to energy flows that result from economic dispatch of their generation 
to native load is inconsistent with the treatment of multistate non-
holding company utilities and is thus discriminatory.
    Blue Ridge seeks clarification that, to avoid double payment for 
transmission, ``CSW must file its compliance filing resolving 
comparability issues and the appropriate CSW ERCOT transmission rate 
prior to September 1, 1996.'' Blue Ridge asserts that CSW must resolve 
a potential conflict between its rate structure and the new PUCT 
wheeling rule by September 1, 1996 (contemplated effective date for 
interim PUCT transmission rates).

Commission Conclusion

    In requiring holding companies to file a pool-wide tariff, the 
Commission does not intend that transmission service provided by the 
operating subsidiaries to one another on behalf of their respective 
native loads be subjected to additional transmission charges. The 
Commission recognizes that the operating subsidiaries of a holding 
company bear cost responsibility for transmission facilities by virtue 
of ownership of such facilities. In many, if not all cases, 
transmission costs are equalized among operating subsidiaries through 
transmission equalization agreements (e.g., AEP's Transmission 
Agreement).
    However, the Commission does intend, pursuant to Order No. 888, 
that holding company operating subsidiaries take transmission service 
under the same tariff rates, terms, and conditions as third-party 
customers that seek transmission service over the holding company 
system. This applies to all holding company systems that rely upon the 
transmission facilities of the individual operating subsidiaries to 
support central economic dispatch--including AEP and Allegheny. 
However, as suggested by Southern and Union Electric, the Commission 
anticipates that transmission service for an operating subsidiary's 
native load would be treated as network service under the pro forma 
tariff. Accordingly, the CP demands of each operating subsidiary's 
native load would establish each operating subsidiary's transmission 
cost responsibility related to network service over the integrated 
transmission facilities of the holding company system.
    Thus, in response to the AL and FL Commissions, Southern, and NU, 
intra-holding company transactions in support of economic dispatch 
would not be subjected to ``additional'' transmission charges.<SUP>204 
The load ratio pricing mechanism of the network portion of the tariff 
should ensure that each operating company bears its proportionate share 
of transmission costs without jeopardizing or otherwise penalizing 
these types of intra-system transactions. Moreover, any off-system 
sales would have to be taken under the point-to-point provisions of the 
tariff. As we noted in Order No. 888, ``it may be necessary for 
registered holding companies to reform their holding

[[Page 12315]]

company equalization agreement to recognize the non-discriminatory 
terms and conditions of transmission service required under the Final 
Rule pro forma tariff.'' <SUP>205 However, nothing in Order No. 888 
mandates any change to the method chosen for apportioning transmission 
revenues among the operating companies, which may be based, for 
example, upon equalizing transmission investment responsibility.
---------------------------------------------------------------------------

    \204\ The Commission notes that Order No. 888 requires that all 
third party tariff customers taking network or point-to-point 
service pay a transmission rate which reflects an appropriate share 
of transmission costs, including those related to transmission 
construction.
    \205\ FERC Stats. & Regs. at 31,729; mimeo at 277.
---------------------------------------------------------------------------

    The concerns raised here by Blue Ridge are resolved on an interim 
basis because the PUCT has accepted the filing of CSW's Federal tariff 
as adequate in the Texas proceeding until differences between the Order 
No. 888 rate structure and the PUCT rate structure are resolved. If, 
CSW implements a new ERCOT transmission tariff in response to actions 
of the PUCT, then affected parties may bring any remaining concerns to 
the Commission's attention at that time through a section 206 
complaint.
    We note that the issue raised here by Blue Ridge is very similar to 
the one raised by Tex-La and East Texas Electric Cooperative, and 
addressed by the Commission's recent order, in Houston Lighting & Power 
Co., 77 FERC para. 61,113 at 61,439 (1996). There, the Commission found 
that it would be premature to address this issue at that time, and 
noted that parties would have an opportunity to raise their concerns 
after the PUCT finalizes its ERCOT tariff.
4. Bilateral Coordination Arrangements
    In the Final Rule, the Commission required that any bilateral 
wholesale coordination agreements executed after the effective date of 
the Final Rule would be subject to the functional unbundling and open 
access requirements set forth in the Rule.<SUP>206 In addition, the 
Commission required that all bilateral economy energy coordination 
contracts executed before the effective date of the Rule be modified to 
require unbundling of any economy energy transaction occurring after 
December 31, 1996. Moreover, the Commission permitted all non-economy 
energy bilateral coordination contracts executed before the effective 
date of the Rule to continue in effect, but subject to section 206 
complaints.
---------------------------------------------------------------------------

    \206\ FERC Stats. & Regs. at 31,729-30; mimeo at 277-78.
---------------------------------------------------------------------------

    To compute the unbundled coordination compliance rate, the 
Commission indicated that the utility must subtract the corresponding 
transmission unit charge in its open access tariff from the existing 
coordination rate ceiling. However, the Commission noted, if a 
utility's transmission operator offers a discounted transmission rate 
to the utility's wholesale marketing department or an affiliate for the 
purposes of coordination transactions, the same discounted rate must be 
offered to others for trades with any party to the coordination 
agreement. In addition, the Commission explained that discounts offered 
to non-affiliates must be on a basis that is not unduly discriminatory.

Rehearing Requests

    SoCal Edison seeks clarification as to how Order No. 888 affects 
package agreements (i.e., bilateral contracts that provide some or all 
of requirements service, coordination service, or transmission 
service). In particular, SoCal Edison asks (1) what specific functions 
of each must be modified to comply with Order No. 888; (2) whether a 
sale of non-firm energy made pursuant to a package agreement must 
comply with the unbundling requirements for coordination contracts; (3) 
whether the requirement to remove preferential transmission access or 
pricing provisions applies to existing or future transmission services 
provided pursuant to package agreements; if so, what is the deadline; 
and (4) whether the rulings with respect to Mobile-Sierra apply to 
package agreements.<SUP>207
---------------------------------------------------------------------------

    \207\ Anaheim, in an answer opposing SoCal Edison's request for 
clarification regarding its package agreements, requests that these 
agreements be dealt with on a case-by-case basis ``in context.'' 
(Anaheim Answer). While answers to requests for rehearing generally 
are not permitted, we will depart from our general rule because of 
the significant nature of this proceeding and accept the Anaheim 
Answer.
---------------------------------------------------------------------------

    APPA argues that the Commission should require all coordination 
arrangements to be subject to Order No. 888. CCEM asserts that to the 
extent non-economy energy coordination agreements are allowed to remain 
bundled, they should be identified in connection with determinations of 
available transfer capacity and, because they should only be a 
transitional matter, should be subject to a sunset date of December 31, 
1996.
    According to Utilities For Improved Transition, requiring the 
subtraction of the current tariff transmission rate from the current 
rate ceiling, without increasing the residual sales price, will force 
transmission providers to fail to recover their full costs of providing 
service because the Commission has previously prohibited these rates 
from including a transmission component (citing Green Mountain, 63 FERC 
para. 61,071 at 61,307-08 (1993) and Cleveland Electric, 63 FERC para. 
61,244 at 62,277-78 (1993)).<SUP>208
---------------------------------------------------------------------------

    \208\ See also VEPCO.
---------------------------------------------------------------------------

    Union Electric also argues that the Commission should delete the 
requirement that the utility subtract the corresponding transmission 
unit charge in its open access tariff from the existing coordination 
rate ceiling. According to Union Electric, actual bilateral economy 
sales do not include adders for recovery of transmission costs, but are 
typically limited to production or generation costs. Union Electric 
further asserts that the definition of economy energy coordination 
agreement is so open-ended, it may apply to many types of coordination 
transactions that are not mere energy economy sales. Union Electric 
argues that a split-the-savings charge cannot be unbundled in the 
manner described by the Commission because it is an incorrect 
assumption that the rate ceiling for every economy energy coordination 
sales agreement includes a transmission cost component. If Union 
Electric is required to arbitrarily subtract a transmission charge for 
its economy sales, it argues that it will be penalized. At a minimum, 
it argues, a utility should be permitted to submit a list of economy 
coordination rate schedules that it believes to be already unbundled 
and should not have to subtract a transmission charge. Alternatively, 
it argues that the Commission should not require unbundling unless the 
Commission determines that the existing rate ceiling has been cost 
justified on a basis that includes an allowance for the full recovery 
of transmission function cost.<SUP>209
---------------------------------------------------------------------------

    \209\ See also Florida Power Corp (if the Commission requires an 
unbundled transmission rate, it must allow transmission providers to 
reformulate their unbundled economy energy agreements to recover 
both their capacity and energy costs and the costs of transmission).
---------------------------------------------------------------------------

Commission Conclusion

    SoCal Edison represents that its package agreements include 
requirements services as well as coordination services. For existing 
bilateral economy energy coordination agreements, Order No. 888, as 
clarified by the Commission's May 17 Order, requires the unbundling of 
transmission from generation for all such contracts on or before 
December 31, 1996.<SUP>210 Thus, any economy energy service included in 
existing package agreements must be unbundled.
---------------------------------------------------------------------------

    \210\ FERC Stats. & Regs. at 31,730; mimeo at 277.
---------------------------------------------------------------------------

    Regarding non-firm energy sales made under a package agreement, 
SoCal Edison provides no information distinguishing that service from 
other

[[Page 12316]]

economy energy coordination transactions, which include all ``if, as 
and when available'' services (see section 35.28(b)(2)). Absent more 
information, non-firm energy sales should be unbundled.
    We further note that our requirements concerning unbundling of 
bilateral coordination arrangements apply regardless of whether such 
arrangements are governed by the public interest or just and reasonable 
standard of review.
    With respect to APPA's concerns, the Final Rule provides that all 
bilateral economy energy coordination contracts executed before the 
effective date of the Final Rule must be modified to require unbundling 
of any economy energy transaction occurring after December 31, 1996. 
Non-economy energy bilateral coordination contracts executed before the 
effective date of the Final Rule, however, were allowed to continue in 
effect, but subject to complaints filed under section 206 of the 
FPA.<SUP>211 We drew this distinction for both policy and practical 
reasons. The ability to use discounts on transmission in order to favor 
short-term economy energy sales made out of the transmission provider's 
own generation was of particular concern to the Commission. Thus, in 
order to eliminate the ability of transmission providers to exercise 
undue discrimination for short-term coordination transactions under 
existing umbrella-type agreements, we required unbundling by December 
31, 1996.<SUP>212 However, non-economy energy coordination agreements 
presented a different situation.
---------------------------------------------------------------------------

    \211\ FERC Stats. & Regs. at 31,730; mimeo at 277.
    \212\ Approximately 300 filings to unbundle this category were 
filed by December 31, 1996.
---------------------------------------------------------------------------

    In the Final Rule, we expressed a particular concern with not 
abrogating non-economy energy coordination agreements, which we 
indicated may reflect complementary long-term obligations among the 
parties.<SUP>213 Non-economy energy coordination agreements consist for 
the most part of long-term reliability arrangements. Providing for the 
abrogation of these arrangements could cause special problems for the 
reliable operation of the grid. Examples include agreements governing 
sales during emergency or maintenance periods. These agreements, unlike 
economy energy agreements where trade is on an ``as, if and when 
available'' basis, often have specified terms governing the parties' 
responsibilities. As a result, many non-economy energy coordination 
agreements are more akin to requirements contracts than to economy 
energy coordination agreements. Therefore, we determined to permit this 
category of contracts to run their course, absent a case specific 
complaint. The burden would be on the complainant to demonstrate that 
the transmission component of a non-economy energy coordination 
agreement is unduly discriminatory or otherwise unlawful. The 
Commission would decide based on the facts of the case whether 
unbundling is the appropriate remedy. Neither CCEM nor APPA have 
presented evidence or convincing arguments as to why these types of 
agreements should be unbundled generically.<SUP>214
---------------------------------------------------------------------------

    \213\ FERC Stats. & Regs. at 31,666; mimeo at 90.
    \214\ Regarding CCEM's request that non-economy energy 
coordination agreements be identified in determining available 
transfer capacity (ATC), we note that all data used to calculate ATC 
and total transfer capacity (TTC) must be made publicly available 
upon request pursuant to section 37.6(b)(2)(ii) of the OASIS 
regulations.
---------------------------------------------------------------------------

    The Commission affirms the requirement in Order No. 888 that the 
transmission rate for any economy energy coordination service be 
unbundled. The Commission states in Order No. 888 that to adequately 
remedy undue discrimination, public utilities must remove preferential 
transmission access and pricing provisions from agreements governing 
their transactions.<SUP>215 In the cases cited by Utilities For 
Improved Transition, the Commission prohibited the utility from 
charging a split-savings rate plus a contribution to fixed costs. The 
Commission has long allowed utilities to set their coordination rates 
by reference to their own costs (cost-based ceilings) or by dividing 
the pool of benefits (fuel cost differentials) brought about by the 
transaction.<SUP>216 Utilities have been free to design a rate using 
either method but not both. Regardless of the method adopted to set a 
bundled rate on file (a seller's own costs or a sharing of transaction 
benefits), a bundled rate constitutes the total charge for all 
components and must now be unbundled.
---------------------------------------------------------------------------

    \215\ FERC Stats. & Regs. at 31,726; mimeo at 268-69.
    \216\ See e.g., Illinois Power Company, 62 FERC para. 61,147 at 
62,062 (1993).
---------------------------------------------------------------------------

    A split-savings rate is set without reference to the seller's fixed 
costs and, therefore, Union Electric's argument is not germane. We are 
not requiring that the present rate be adjusted upward or downward. 
Rather, we are requiring disassembly of the existing rate into 
component parts one of which represents the rate being charged for 
transmission service. If a utility is no longer satisfied that an 
existing rate is compensatory, with regard to either the generation 
component or the transmission component, it may file an appropriate 
revision under section 205.

ISO Principles

    In the Final Rule, the Commission set out certain principles that 
will be used in assessing ISO proposals that may be submitted to the 
Commission in the future.<SUP>217 The Commission emphasized that these 
principles are applicable only to ISOs that would be control area 
operators, including any ISO established in the restructuring of power 
pools.
---------------------------------------------------------------------------

    \217\ FERC Stats. & Regs. at 31,730-32; mimeo at 279-86.
---------------------------------------------------------------------------

    The Commission set forth the following principles for ISOs:
    1. The ISO's governance should be structured in a fair and non-
discriminatory manner.
    2. An ISO and its employees should have no financial interest in 
the economic performance of any power market participant. An ISO should 
adopt and enforce strict conflict of interest standards.
    3. An ISO should provide open access to the transmission system and 
all services under its control at non-pancaked rates pursuant to a 
single, unbundled, grid-wide tariff that applies to all eligible users 
in a non-discriminatory manner.
    4. An ISO should have the primary responsibility in ensuring short-
term reliability of grid operations. Its role in this responsibility 
should be well-defined and comply with applicable standards set by NERC 
and the regional reliability council.
    5. An ISO should have control over the operation of interconnected 
transmission facilities within its region.
    6. An ISO should identify constraints on the system and be able to 
take operational actions to relieve those constraints within the 
trading rules established by the governing body. These rules should 
promote efficient trading.
    7. The ISO should have appropriate incentives for efficient 
management and administration and should procure the services needed 
for such management and administration in an open competitive market.
    8. An ISO's transmission and ancillary services pricing policies 
should promote the efficient use of and investment in generation, 
transmission, and consumption. An ISO or an RTG of which the ISO is a 
member should conduct such studies as may be necessary to identify 
operational problems or appropriate expansions.
    9. An ISO should make transmission system information publicly 
available on a timely basis via an electronic

[[Page 12317]]

information network consistent with the Commission's requirements.
    10. An ISO should develop mechanisms to coordinate with neighboring 
control areas.
    11. An ISO should establish an alternative dispute resolution (ADR) 
process to resolve disputes in the first instance.

Rehearing Requests

General Comments

    NY Municipal Utilities argue that if the NYPP participants (or 
other tight pools) elect to establish an ISO, the ISO Principles should 
be made mandatory for the protection of transmission dependent 
utilities.
    NY Com asks the Commission to clarify that it will allow 
flexibility to states and utilities in structuring proposals that meet 
the goals underlying the ISO principles. It explains that the parties 
to New York's electric competition proceeding are discussing the 
formation of an ISO in which transmission owners control the system 
operator, but would have to divest their competitive generation. NY Com 
further notes that it has not decided that matter yet, but it does not 
want to see such options foreclosed.
    Minnesota P&L argues that certain functions, particularly those 
involving local area circumstances and safety, are better handled at 
the local level. It further argues that control area responsibilities 
of an ISO should focus on regional issues and operations, and on 
establishing and enforcing uniform criteria and guidelines for local 
control area operations in order to assure non-discriminatory treatment 
of all transmission customers.
    AMP-Ohio asserts that the Commission should require the separation 
of transmission, generation and distribution through an ISO and, at a 
minimum, the Commission should include a Stage 3 of implementation to 
bring ISOs to reality.

ISO Principle 1

    NYPP argues that the Commission should not include a rigid ban on 
transmission owner leadership in ISO governance because it is the 
transmission owner that is ultimately responsible for the reliability 
of the bulk power system.<SUP>218
---------------------------------------------------------------------------

    \218\ Sithe, in a response to the NYPP's request for 
clarification, opposes the ``transmission owners only'' ISO sought 
by NYPP. (Sithe Response). Subsequently, NYPP filed an objection to 
Sithe's pleading and request that it be rejected. (NYPP Objection). 
NYPP explains that its rehearing was a request that the Commission 
refrain from setting fixed rules for ISO governance in advance, not 
an argument that the Commission should adopt one particular 
mechanism or another for all ISOs. While answers to requests for 
rehearing generally are not permitted, we will depart from our 
general rule because of the significant nature of this proceeding 
and accept the Sithe Response and NYPP Objection.
---------------------------------------------------------------------------

ISO Principle 2

    NYPP asks that the Commission revise this principle to take a more 
flexible approach to significant employee issues. NYPP explains that it 
has 81 management employees on the payroll of individual member systems 
and that pension rights (accrual rights based on an average salary) and 
medical insurance (preexisting conditions) are through the individual 
member systems.

ISO Principle 3

    SoCal Edison asks that this principle be revised to permit a 
separate access charge for each utility in order to avoid cost 
shifting. Anaheim seeks revision of this principle to require that an 
ISO provide comparable compensation to all transmission owners that 
make transmission facilities available for use by the ISO.

ISO Principle 5

    Anaheim asks that this principle be revised to make clear that ISO 
arrangements should seek to encourage participation by all transmission 
owners within the region.

ISO Principle 6

    NYPP seeks clarification that an ISO needs control over more than 
some generation facilities because the more generating facilities 
operating under an ISO the more reliability there is. Thus, it asserts 
that the Commission should clarify that its description of ISO control 
of generation does not require only a minimalist approach to ISO 
generation control.

ISO Principle 8

    SoCal Edison seeks revision of this principle to remove the 
language linking the ISO to performing studies necessary to identify 
appropriate grid expansions. According to SoCal Edison, an ISO should 
not be a project sponsor or should not conduct planning studies to 
determine what facilities should be constructed because those actions 
would compromise its independence. In addition, SoCal Edison seeks 
revision of this principle to permit a transmission usage charge that 
incorporates locational marginal cost pricing for managing transmission 
congestion.

Commission Conclusion

    We reaffirm our strong commitment to the concept of ISOs, and to 
the ISO principles described in Order No. 888. We continue to believe 
that properly structured ISOs can be an effective way to comply with 
the comparability requirements of open access transmission service. 
Nevertheless, we do not believe at this time that it is appropriate to 
require public utilities or power pools to establish ISOs, as suggested 
by AMP-Ohio. We think it is appropriate to permit some time to confirm 
whether functional unbundling will remedy undue discrimination before 
reconsidering our decision that ISO formation should be voluntary.
    A number of the above rehearing requests on ISOs are from New York 
parties and deal with ongoing efforts in New York that would reform the 
New York Power Pool pooling agreements, restructure power markets, and 
possibly form an ISO. Some of these arguments are in apparent conflict; 
for example, the NY Municipal Utilities argue that the 11 ISO 
principles should be made mandatory if the New York Power Pool 
participants elect to establish an ISO, while the NY Com argues that 
the Commission should clarify Order No. 888 to state that it will allow 
flexibility to states and utilities in structuring proposals that meet 
the goals underlying the ISO principles. We note that since the time 
the rehearing requests were filed, the NY Power Pool has filed 
amendments to its pooling agreements on December 30, 1996 and also has 
filed, on January 31, 1997, various agreements and tariffs designed to 
implement an ISO and market exchange. To the extent the rehearing 
requests from New York parties deal with matters that have been filed 
with the Commission subsequent to the rehearing requests, the 
Commission will address the issues raised in the context of those 
filings.
    In response to NY Com's request for clarification that we provide 
flexibility to states and their utilities in structuring ISO proposals, 
the Commission at this time clearly cannot, and does not intend to, 
prescribe a ``cookie cutter'' approach to ISOs. However, the Commission 
does believe that certain basic principles must be met to ensure non-
discriminatory transmission services. We reaffirm our view that ISO 
Principles 1 (independence with respect to governance) and 2 
(independence with respect to financial interests) are fundamental to 
ensuring that an ISO is truly independent and would not favor any class 
of transmission users. As the Commission stated in its recent order on 
the proposed PJM ISO:

    The principle of independence is the bedrock upon which the ISO 
must be built if stakeholders are to have confidence that it

[[Page 12318]]

will function in a manner consistent with this Commission's pro-
competitive goals.<SUP>[219]
---------------------------------------------------------------------------

    \219\ Atlantic City Electric Company, et al., 77 FERC para. 
61,148 (1996) (mimeo at 36-41); see also Pacific Gas & Electric 
Company, 77 FERC para. 61,204 (1996).

ISO governance that is disproportionately influenced by transmission 
owners, unless they have fully divested their interests in generation, 
is not consistent with ISO Principle 1. We remain concerned that ISO 
proposals that do not include governance by a fair representation of 
all system users may not be independent, although we reserve final 
judgment on any specific governance structure until we have an 
opportunity to review a specific proposal.<SUP>220
---------------------------------------------------------------------------

    \220\ In making this finding, we are not suggesting that an 
independent transmission company, which owns only transmission, is 
undesirable. However, an ISO, which separates ownership and 
operation, is designed in large part to recognize that transmission 
owners today have significant generation or load interests that may 
bias their operational decisions.
---------------------------------------------------------------------------

    In response to the argument made by NYPP that transmission owner 
leadership in ISO governance may be needed because transmission owners 
are ultimately responsible for the reliability of the bulk power 
system, we emphasize that reliability is of primary importance to this 
Commission and that the formation and operation of an ISO should not in 
any way impair reliability. We believe that one of the main purposes of 
an ISO is to make an independent party, the ISO, responsible for at 
least short-term reliability. Even if both the transmission owners and 
the ISO will be responsible for some aspects of reliability, this does 
not affect our finding that the governance of the ISO must be 
independent of the transmission owners so that the ISO can carry out 
its own responsibilities in a not-unduly discriminatory manner.
    In response to arguments of the NYPP that the Commission should 
revise Principle 2 to take a more flexible approach to employee issues, 
we reaffirm the necessity of requiring the employees of an ISO to be 
financially independent of market participants and note that Principle 
2 suggests that a short transition period should be adequate for ISO 
employees to sever all financial ties with former transmission owners. 
We recognize that some flexibility may be necessary regarding the 
length of a transition period, but believe that ISO employees must in 
fairly short order be independent of all financial ties to any market 
participants, if we are to achieve not unduly discriminatory practices 
in generation and transmission markets.
    A number of additional parties seek other revisions to or 
clarifications of the ISO Principles. For example, Minnesota P&L 
requests clarification or rehearing to ensure that the Commission 
provides sufficient flexibility to permit local operators, under the 
general supervision and control of the ISO, to perform local 
operational functions, such as performing switching operations. In 
response to this concern, we note that Principle 3 (open access under a 
single tariff) says that the portion of the transmission grid operated 
by a single ISO should be as large as possible. Our view, as described 
above, is that an ISO, which includes all affected users, should be 
responsible for operation of the system and ensuring reliability. The 
ISO may use some combination of actual physical control over facilities 
and virtual control of facilities by others (i.e., the ISO exercises 
control over facilities by instructing the transmission owners' or 
generation owners' staffs as to the actions to be taken). The broad 
range of interested parties that establish the ISO must determine what 
services the ISO will perform and what services transmission owners or 
others will perform under ISO supervision.
    We deny the requests by Socal Edison and Anaheim to revise ISO 
Principle 3 to permit separate access charges for each utility to avoid 
cost shifting. We think ISO Principle 3 already provides sufficient 
flexibility to accommodate the concerns of these parties with respect 
to design of access charges and compensation to owners for transmission 
facilities under operational control of the ISO.
    Similarly, we see no reason to revise Principle 5 (control of 
interconnected operations) as requested by Anaheim. We agree with 
Anaheim that wide participation of transmission owners in a region will 
help ensure open access and increase efficient transmission 
coordination. ISO Principle 3 says that the portion of the transmission 
grid operated by a single ISO should be as large as possible. ISO 
Principle 5 says that an ISO should have control over the operation of 
interconnected transmission facilities within its region. These 
principles, as written, address Anaheim's concern.
    With respect to NYPP's request for clarification of ISO Principle 6 
(dealing with constraints), we note that the description of ISO 
Principle 6 in the Final Rule says that the ISO may need to exercise 
some level of operational control over generation facilities in order 
to regulate and balance the power system.<SUP>221 We do not think it is 
appropriate for the Commission to give further generic guidance now on 
what constitutes the proper level of operational control over 
generation. The ISO, including all stakeholders, needs to address this 
issue, based on the structure of power markets and perhaps other local 
considerations, in preparing a specific proposal for our approval.
---------------------------------------------------------------------------

    \221\ FERC Stats. & Regs. at 31,731; mimeo at 283.
---------------------------------------------------------------------------

    Finally, we deny SoCal Edison's request for revision of ISO 
Principle 8 (pricing). In response to SoCal Edison's concern, ISO 
Principle 8 allows the use of appropriate locational marginal cost 
pricing. The principle allows flexibility regarding which regional 
organization of market participants (ISO or RTG) conducts the necessary 
studies to identify the need for expansion. We are unpersuaded by SoCal 
Edison's arguments that the fact that an ISO is involved in planning 
for transmission facility expansion would in any way compromise the 
independence of the ISO.

G. Pro Forma Tariff

    In the Final Rule, the Commission combined the requirements for 
point-to-point transmission service and network transmission service 
into a single pro forma tariff.<SUP>222 The Commission explained that 
this eliminates many of the differences between the two NOPR pro forma 
tariffs, provides a unified set of definitions, and consolidates 
certain common requirements such as the obligation to provide ancillary 
services. The Commission also noted that it was issuing an accompanying 
Notice of Proposed Rulemaking in Docket No. RM96-11-000 in which it was 
seeking comments on whether a different form of open access tariff--one 
based solely on a capacity reservation system--might better accommodate 
competitive changes occurring in the industry while ensuring that all 
wholesale transmission service is provided in a fair and non-
discriminatory manner. <SUP>223
---------------------------------------------------------------------------

    \222\ FERC Stats. & Regs. at 31,733; mimeo at 288-89.
    \223\ FERC Stats. & Regs. at 31,733; mimeo at 289.
---------------------------------------------------------------------------

1. Tariff Provisions That Affect The Pricing Mechanism
a. Non-Price Terms and Conditions
    In the Final Rule, the Commission explained that the Final Rule pro 
forma tariff is intended to initiate open access, with non-price terms 
and conditions based on the contract path model of power flows and 
embedded cost ratemaking.<SUP>224 It emphasized that the Final Rule pro 
forma tariff is not intended to signal a preference for contract path/
embedded cost pricing for the future. The Commission indicated

[[Page 12319]]

that it will in the future entertain non-discriminatory tariff 
innovations to accommodate new pricing proposals.
---------------------------------------------------------------------------

    \224\ FERC Stats. & Regs. at 31,734-35; mimeo at 291-93.
---------------------------------------------------------------------------

    The Commission further indicated that, by initially requiring a 
standardized tariff, it intends to foster broad access across multiple 
systems under standardized terms and conditions. However, the 
Commission emphasized that the tariff provides for certain deviations 
where it can be demonstrated that unique practices in a geographic 
region require modifications to the Final Rule pro forma tariff 
provisions.
    Finally, the Commission stated that it will allow utilities to 
propose a single cost allocation method for network and point-to-point 
transmission services.
b. Network and Point-to-Point Customers' Uses of the System (so called 
``Headroom'')
    In the Final Rule, the Commission explained that it will not allow 
network customers to make off-system sales within the load-ratio 
transmission entitlement at no additional charge.<SUP>225 The 
Commission further explained that use of transmission by network 
customers for non-firm economy purchases, which are used to displace 
designated network resources, must be accorded a higher priority than 
non-firm point-to-point service and secondary point-to-point service 
under the tariff. In addition, the Commission found that off-system 
sales transactions, which are sales other than those to serve the 
transmission provider's native load or a network customer's load, must 
be made using point-to-point service on either a firm or non-firm 
basis. In rejecting the ``headroom'' concept (where a network customer 
can make off-system sales as long as its total use of the system does 
not exceed its coincident peak demand), the Commission explained that 
it was not requiring any utility to take network service to integrate 
resources and loads and if any transmission user (including the public 
utility) prefers to take flexible point-to-point service,<SUP>226 they 
are free to do so. Further, the Commission explained that any point-to-
point customer may take advantage of the secondary, non-firm 
flexibility provided under point-to-point service equally, on an as-
available basis.
---------------------------------------------------------------------------

    \225\ FERC Stats. & Regs. at 31,751; mimeo at 342-43.
    \226\ See Florida Municipal Power Agency v. Florida Power & 
Light Company, 74 FERC para. 61,006 at 61,013 and n.70 (1996).
---------------------------------------------------------------------------

Rehearing Requests

    A number of entities argue that it is unreasonable to permit firm 
point-to-point customers to receive non-firm service, up to their 
contract demand, at no additional charge, at secondary receipt and 
delivery points, but to require transmission providers and network 
customers to purchase transmission for all off-system sales, including 
non-firm sales made in competition with sales made by the point-to-
point customer.<SUP>227 FPL asserts that having built and paid for the 
entire transmission network, the owner and the network customer should 
have the flexibility to use the network as they need. Utilities For 
Improved Transition declare that just as the firm point-to-point 
customer is permitted to maximize the use of its contract demand, the 
transmission provider and network customer should be entitled to 
maximize their long-term fixed cost obligation (citing AES Power, Inc., 
69 FERC para. 61,345 at 62,300 (1994) (AES) for the proposition that 
the utility and its native load customers are obligated to pay all the 
costs of the transmission system without regard to the amount of energy 
actually scheduled).
---------------------------------------------------------------------------

    \227\ E.g., FPL, Utilities For Improved Transition, TDU Systems, 
Carolina P&L, AEC & SMEPA, VT DPS, EEI.
---------------------------------------------------------------------------

    FPL and Carolina P&L suggest two possible solutions: (1) allow the 
transmission provider and network customer to have rights to the 
headroom beneath their fixed cost obligations at no additional charge, 
or (2) restrict the no-charge use of firm point-to-point headroom to 
transmission service associated with non-firm purchases to serve load. 
Under either of these options, they assert, the firm point-to-point 
customer's rights to make non-firm off-system sales would be on an even 
competitive footing with the transmission provider or network customer.
    PA Coops maintain that network customers should have the right to 
reassign/sell unused capacity below their 12-month rolling average peak 
demand at no additional charge. Cajun argues that network customers 
should be allowed to use the transmission system for non-firm (and 
perhaps firm) coordination transactions at no additional cost, provided 
the network customer's total use of the transmission system does not 
exceed its load ratio share. Cajun notes that the Commission seems to 
have determined elsewhere in the Rule that a network customer has 
already paid for the full use of its load ratio share (citing mimeo at 
332 and 338). In addition, Cajun states that requiring the network 
customer to use point-to-point service results in the network customer 
paying twice for the same capacity.
    VT DPS argues that the Commission should permit network users to 
make limited use of their network capacity to make off-peak off-system 
sales. It asserts that UtiliCorp's network tariff, filed in Docket No. 
ER95-203, provides a useful model: ``the level of capacity utilized by 
the company or the customer for its combined network load and off-
system sales load would be fixed by the tariff as the highest 
coincident peak load experienced by the transmitting utility in the 
three years preceding the off-system sale.'' According to VT DPS, this 
places all firm users on a par. In contrast, VT DPS argues that the 
Commission's solution is arbitrary and patently inadequate. VT DPS 
claims that concerned parties are not just transmission providers, but 
include state agencies and entities that need to take network service. 
VT DPS further argues that the lower priority for secondary service 
under the point-to-point tariff may pose an unacceptable risk to public 
utilities with firm obligations to serve their load, and having to 
agree to a fixed demand quantity may be unsatisfactory for public 
utilities with growing customer loads and a statutory obligation to 
serve those loads.
    LEPA argues that:

[t]he Commission erred in not finding that in order to compete, one 
must be able to utilize base load units of 500MW size because entry 
without the ability to employ such base load units would make the 
putative entrant unable to compete; that in order to employ such 
units, or portions of them, the entrant had to engage in the 
coordinated development of base load units; that such coordinated 
development requires use of transmission for that purpose so as to 
be able to sell portions of the output of a baseload unit off-
system, and that without 'headroom,' the cost of transmission for 
that purpose would not be comparable with the cost of transmission 
for the same purpose of the owner of the transmission. (LEPA at 5).

Commission Conclusion

    The requests for rehearing on this issue present no arguments that 
were not fully considered in Order No. 888. Petitioners continue to 
claim that transmission providers and network customers are 
competitively disadvantaged vis-a-vis point-to-point transmission 
customers due to the point-to-point customers' ability to use as 
available, non-firm service over secondary points of receipt and 
delivery at no additional cost. The Commission attempted to strike a 
balance on this issue in Order No. 888 by allowing both network and 
point-to-point services to be priced on the same basis (i.e., no longer 
summarily rejecting the use of the average of the 12 monthly system

[[Page 12320]]

peaks as the denominator for the rate for point-to-point service). 
Additionally, the Commission established a lower priority for the non-
firm secondary point-to-point service than for either economy purchases 
by network customers or for stand-alone non-firm point-to-point 
service, as discussed in Section IV.G.3.b. Accordingly, we believe that 
these concerns have been sufficiently addressed.
    Furthermore, these entities want to be allowed to make off-system 
sales under their network service at no additional charge as long as 
their total use of the system does not exceed their load ratio share. 
They claim that it is inequitable not to allow such ``headroom'' sales 
under the network service while allowing firm point-to-point customers 
to use non-firm transmission service up to their contract demands using 
secondary receipt and delivery points at no additional charge. As the 
Commission stated in Order No. 888, customers are not obligated to take 
network transmission service.<SUP>228 If customers want to take 
advantage of the as-available, non-firm service over secondary points 
of receipt and delivery through the point-to-point service, they may 
elect to take firm point-to-point transmission service in lieu of the 
network service. We further note that transmission providers must take 
point-to-point transmission service for their own off-system sales, 
which results in comparable treatment for both the transmission 
provider and network customers. Transmission providers and other 
customers taking point-to-point transmission service do not need to be 
allowed to make ``headroom'' sales because they have access to as-
available, non-firm service over secondary points of receipt and 
delivery at no additional charge through their point-to-point service.
---------------------------------------------------------------------------

    \228\ FERC Stats. & Regs. at 31,751; mimeo at 342-43.
---------------------------------------------------------------------------

    Cajun's argument that a network customer has already paid for the 
full use of its load-ratio share of the system ignores the fact that 
network service is based on integrating a network customer's resources 
with its load, not on making off-system sales. This is why network 
customers pay for service on a load-ratio basis. If Cajun is concerned 
that it may need to pay for both network service and point-to-point 
service, Cajun can simply elect to take point-to-point service for all 
of its transmission needs.
    VT DPS' claim that the lower priority accorded to transmission 
service to secondary points of receipt and delivery under flexible 
point-to-point service would present an ``unacceptable risk'' to public 
utilities is unsubstantiated. If the risk of having this secondary 
service curtailed is too great, this customer has the option to: (1) 
take stand-alone non-firm point-to-point service (which has a higher 
priority), (2) take this service on a firm point-to-point basis, or (3) 
take network service, which has a higher priority for economy purchases 
than either stand-alone non-firm or secondary non-firm point-to-point 
service.
    With respect to LEPA's argument, the Commission has the goal of 
encouraging competition in the generation market, not discouraging 
generation competition by erecting barriers to entry such as arbitrary 
generator size. Furthermore, LEPA's argument that comparability is not 
achieved without allowing headroom is incorrect because both network 
customers as well as the transmission provider must obtain point-to-
point transmission service to accommodate transmission for wholesale 
sales.
c. Load Ratio Sharing Allocation Mechanism for Network Service
    In the Final Rule, the Commission concluded that the load ratio 
allocation method of pricing network service continues to be reasonable 
for purposes of initiating open access transmission.<SUP>229 The 
Commission also reaffirmed the use of a twelve monthly coincident peak 
(12 CP) allocation method because it believed the majority of utilities 
plan their systems to meet their twelve monthly peaks. However, the 
Commission stated that it would allow utilities to file another method 
(e.g., annual system peak) if they demonstrate that it reflects their 
transmission system planning.
---------------------------------------------------------------------------

    \229\ FERC Stats. & Regs. at 31,736; mimeo at 296-97.
---------------------------------------------------------------------------

    With respect to concerns raised about pancaked rates for network 
service provided to load served by more than one network service 
provider, the Commission indicated that if a customer wishes to exclude 
a particular load at discrete points of delivery from its load ratio 
share of the allocated cost of the transmission provider's integrated 
system, it may do so. However, customers that elect to do so, the 
Commission explained, must seek alternative transmission service for 
any such load that has not been designated as network load for network 
service. The Commission indicated that this option is also available to 
customers with load served by ``behind the meter'' generation <SUP>230 
that seek to eliminate the load from their network load ratio 
calculation.
---------------------------------------------------------------------------

    \230\ Behind-the-meter generation means generation located on 
the customer's side of the point of delivery.
---------------------------------------------------------------------------

(1) Multiple Control Area Network Customers

Rehearing Requests

    A number of entities argue that excluding load from the designation 
of Network Load does not solve the pancaking problem and results in the 
network customer paying even more transmission charges. They contend 
that a network customer must still pay two network charges and point-
to-point charges to be able to operate its resources across two control 
areas. The Commission's approach, they argue, makes it impossible for a 
network customer with loads and resources in multiple control areas to 
integrate those loads and resources on an economic dispatch 
basis.<SUP>231 In essence, these entities state that a network customer 
must frequently dispatch resources in one transmission provider's 
control area (control area A) to serve that customer's load (in the 
case of a G&T cooperative, the load of a member system or third-party 
requirements customer) located in an adjacent control area of another 
transmission provider (control area B). As a result, they believe, the 
tariff essentially requires that network load in control area B, served 
by resources in control area A, must be counted as load in control area 
B. Alternatively, they believe that the tariff allows the transmission 
of resources in control area A to load in control area B as point-to-
point transmission that requires an additional charge. These entities 
argue that either of these situations produces uneconomic results for 
multiple control-area network customers.
---------------------------------------------------------------------------

    \231\ E.g., NRECA, TDU Systems, Blue Ridge.
---------------------------------------------------------------------------

    To avoid these problems, these entities propose that a network 
customer be allowed to use its network service to transmit power and 
energy from resources in control area A to serve load in control area B 
without designating the control area B load as network load for billing 
purposes. These entities suggest that no additional compensation should 
be required if such transfers to load in adjacent control areas plus 
other network transactions on behalf of the transmission customer in 
control area A do not exceed the customer's coincident demand in 
control area A. They also maintain that the ultimate solution is a 
regional system operated by an ISO. At the very least, TDU Systems 
contends, the Commission should require provision of service to network 
customers with loads and resources

[[Page 12321]]

located on multiple systems under a rate that recovers the customer's 
load ratio share--but no more--of the transmission owners' collective 
transmission investment in the control areas that the customer 
straddles.
    AMP-Ohio maintains that rational economic transmission pricing 
policies demand elimination of the pancaking of rates caused by the 
arbitrary ownership boundaries of individual utilities.
    TAPS asks that the Commission clarify that the Commission will look 
closely at how to create and promote region-wide rates when evaluating 
mergers and market-based rate proposals. It argues that the Commission 
should be receptive to section 211 filings seeking non-pancaked rates 
and should establish a Stage 3 for the purpose of addressing directly 
the need for transmission access on a non-pancaked, regional basis.

Commission Conclusion

    In the Final Rule, the Commission addressed concerns regarding 
pancaked rates for network service for customers with load in multiple 
control areas.<SUP>232 Tariff section 31.3 allows a network customer 
the option to exclude all load from its designated network load that is 
outside the transmission provider's transmission system, and to serve 
such load using point-to-point transmission service.
---------------------------------------------------------------------------

    \232\ FERC Stats. & Regs. at 31,736; mimeo at 297.
---------------------------------------------------------------------------

    NRECA and TDU Systems, however, argue that network customers 
located in multiple control areas should not have to pay for any 
additional point-to-point transmission service to make sales to non-
designated load located in a separate control area. We disagree. 
Because the additional transmission service to non-designated network 
load outside of the transmission provider's control area is a service 
for which the transmission provider must separately plan and operate 
its system beyond what is required to provide service to the customer's 
designated network load, it is appropriate to have an additional charge 
associated with the additional service.
    AMP-Ohio's concerns regarding ``arbitrary ownership boundaries of 
individual utilities,'' and TAP's proposal to require regional rates 
are beyond the scope of Order No. 888.<SUP>233 However, as the 
Commission explained in the Final Rule, it encourages the voluntary 
formation of regional transmission groups, as well as the establishment 
of regional ISOs, and will address those matters on a case-by-case 
basis.
---------------------------------------------------------------------------

    \233\ These entities do not explain how the Commission could 
force non-public utility control area operators, of which there are 
approximately 62 out of 138 in the United States (as of October 
1996), to accede to these pricing policies.
---------------------------------------------------------------------------

(2) Twelve Monthly Coincident Peak v. Annual System Peak

Rehearing Requests

    Several utilities ask that the Commission eliminate the requirement 
that charges for network service be calculated using a 12-month rolling 
average load ratio share and allow utilities discretion to determine 
the way network customers pay. <SUP>234 They assert that the 
requirement makes it impossible to recover the full cost of service 
when customers begin or terminate service. They suggest a unit charge 
based on a formula rate that is trued up each year or a month-by-month 
load ratio share calculation.
---------------------------------------------------------------------------

    \234\ E.g., Utilities For Improved Transition, Florida Power 
Corp, VEPCO.
---------------------------------------------------------------------------

    NE Public Power District states that the definition of load ratio 
share in section 1.16 of the pro forma tariff, taken together with 
sections 34.2 and 34.3 of the pro forma tariff require the use of the 
12-CP method and the inclusion of losses to the generator bus. This, it 
argues, is inconsistent with the Commission's statement that 
``[u]tilities that plan their systems to meet an annual system peak * * 
* are free to file another method if they demonstrate that it reflects 
their transmission system planning.'' (NE Public Power District at 22-
23). NE Public Power District argues that utilities should be allowed 
to use CP demands measured at delivery points at some common specified 
voltage. It further asks the Commission to clarify whether the monthly 
peak includes or excludes transmission losses.
    EEI and AEP argue that transmission reservations for services of 
less than one month's duration and any discounted firm transactions 
should not be counted in the load ratio calculation when determining 
the 12 CP on point-to-point rates, but that the revenues from these 
services should be credited to all firm transmission users.
    Montana Power argues that the Commission's pricing approach 
discriminates against native load customers because all non-network 
uses of the system do not occur at full, non-discounted prices for the 
entire month and the effects of discounts will be shouldered by native 
load customers. According to Montana Power, this is a disincentive to 
utilities to offer discounts and creates a possibility of gaming by 
network customers buying one day firm point-to-point reservations to 
reduce their network load ratio shares.

Commission Conclusion

    While the Commission reaffirmed the use of a twelve monthly 
coincident peak (12 CP) allocation method for pricing network service 
in the Final Rule, the Commission also stated:

[u]tilities that plan their systems to meet an annual system peak * 
* * are free to file another method if they demonstrate that it 
reflects their transmission system planning.\235\
---------------------------------------------------------------------------

    \235\ FERC Stats. & Regs. at 31,736; mimeo at 296-97.

Accordingly, utilities are free to propose in a section 205 filing an 
alternative to the use of the 12-month rolling average (e.g., annual 
system peak) in the load ratio share calculation, subject to 
demonstrating that such alternative is consistent with the utility's 
transmission system planning and would not result in overcollection of 
the utility's revenue requirement. Any proposed alternative would also 
be subject to any future filing conditions established by the 
Commission.\236\
---------------------------------------------------------------------------

    \236\ FERC Stats. & Regs. at 31,770; mimeo at 398-99.
---------------------------------------------------------------------------

    We also are not convinced that we should require the calculation of 
load ratios using a particular method on a generic basis. Any such 
proposals, including those concerning the treatment of discounted firm 
transmission transactions in the load ratio calculation and revenue 
credits associated with such transactions, are best resolved on a fact-
specific, case-by-case basis.
    Finally, the Final Rule does not prohibit utilities from ``us[ing] 
CP demands measured at delivery points at some common specified 
voltage'' as claimed by NE Public Power District. Treatment of 
transmission losses can be accomplished in different ways by different 
transmission providers under the pro forma tariff, such as adjustment 
to a consistently applied voltage level.
    Regarding NE Public Power District's allegation that certain 
sections of the pro forma tariff do not allow the use of the annual 
system peak method in the load ratio share calculation, the Commission 
recognizes that certain rate methodologies may require minor 
adjustments to the non-price terms and conditions to be consistent with 
the proposed rate methodology. However, any modifications to the non-
price terms and conditions established in the pro forma tariff must be 
fully supported by the utility and the appropriateness of such proposed 
changes will be evaluated by the Commission for

[[Page 12322]]

consistency with the proposed rates or rate methodologies. The 
remainder of NE Public Power District's concerns are case-specific and 
should be raised by NE Public Power District at such time as a 
transmission provider makes a filing.
(3) Load and Generation ``Behind the Meter''

Rehearing Requests

    Several entities request clarification \237\ concerning the 
definition of Network Load in pro forma tariff section 1.22, which 
provides, in pertinent part, that:

    \237\ E.g., AMP-Ohio, TAPS.

    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.

    These entities maintain that section 1.22 is too restrictive and is 
inconsistent with the Final Rule's treatment of load served from 
``behind the meter'' generation.\238\ Specifically, these entities 
request that the Commission clarify that a network customer can exclude 
from its designated network load a portion of load at a discrete point 
of delivery, which is served from generation behind the meter. In 
support of this position, a number of petitioners cite to FMPA v. FPL, 
74 FERC para. 61,006 at 61,012-13, in which they claim the Commission 
allowed network customers to exclude load served by behind the meter 
generation.\239\
---------------------------------------------------------------------------

    \238\ See FERC Stats. & Regs. at 31,736 and 31,743; mimeo at 297 
and 317.
    \239\ E.g., TAPS, Central Minnesota Municipal.
---------------------------------------------------------------------------

    TAPS asserts that there is no operational or economic reason to 
require the designation of all load at a discrete point of delivery as 
network load.
    FMPA argues that network customers should not be charged a network 
rate to use their own transmission (or distribution) system to serve 
loads that are located beyond the transmission owner's system. FMPA 
interprets the Final Rule on this issue as allowing a network customer 
that has behind-the-meter generation to serve part of its behind the 
meter load from such generation; thus, a customer can exclude that 
load, which is served without using the transmission provider's 
transmission system, from the load ratio share. FMPA's interpretation 
of section 1.22 is that ``a network customer may not import power using 
both point-to-point and network transmission service at the same 
delivery point, but that this Section does not prevent a network 
customer from serving load from generation when both are behind the 
delivery point and when the transaction does not rely upon use of the 
transmission provider's transmission system.'' (FMPA at 5). FMPA 
requests that the Commission clarify the language in section 1.22 
consistent with its interpretation above.
    Michigan Systems asks the Commission to modify section 1.22 because 
the ``clause may be interpreted to require network integration 
transmission service customers to pay a second time for the 
transmission of power that is already being transmitted under other 
arrangements, such as transmission ownership. The clause could also be 
interpreted to allow the transmission provider to charge customers for 
the transmission of power which does not use the transmitter's system, 
such as for transmission from 'behind the meter' generation to 'behind 
the meter' load.'' (Michigan Systems at 5-13).
    Wisconsin Municipals ask the Commission to ``clarify that a partial 
designation is appropriate if (1) only part of the load behind a 
particular delivery point relies upon the transmission provider's 
transmission system for service or (2) a network customer is 
responsible for serving only a portion of the load behind a discrete 
delivery point.'' (Wisconsin Municipals at 17-18).
    Blue Ridge asks the Commission to clarify that it intended to allow 
for multiple ownership of resources by customers who are not network 
customers.

Utility Position

    FPL and Carolina P&L ask the Commission to clarify that section 
1.22 and the Rule (see also Original Sheet No. 94 and FMPA I, 67 FERC 
para. 61,167 at 61,481-82 (1994)) mean that regardless of whether or 
not a customer has behind the meter or local generation at a delivery 
point, if a customer wants to purchase network service to serve load at 
a delivery point, it must purchase network service for all such load--
the customer cannot split the load into network and point-to-point 
components at a specific point of delivery.\240\ Otherwise, FPL states, 
there would be a split system with the potential to game the system and 
problems with how it would work.
---------------------------------------------------------------------------

    \240\ Utilities For Improved Transition argues that a 
transmission dependent utility should be required to serve its load 
using only network transmission service. It asserts that such a 
utility should not be allowed to avoid its full cost responsibility 
by using point-to-point firm during peak periods and non-firm 
service during non-peak periods. See also VEPCO.
    Moreover, FMPA filed an answer in opposition to the requests for 
clarification of FP&L, Carolina P&L and others concerning the 
definition of network load and related issues. (FMPA Answer). 
Likewise, Michigan Systems and TAPS filed answers opposing these 
requests for rehearing. (Michigan Systems Answer and TAPS Answer). 
While answers to requests for rehearing generally are not permitted, 
we will depart from our general rule because of the significant 
nature of this proceeding and accept the FMPA Answer, Michigan 
Systems Answer and TAPS Answer.
---------------------------------------------------------------------------

    AEP argues that the option in section 1.22 of excluding load from 
network load should be deleted. AEP states that, as the Commission 
recognized in its original FMPA v. FPL order, the provision is contrary 
to the comparability standard. Specifically, AEP argues that 
transmission-owning utilities do not and cannot offer themselves 
partial integration service electing to pay only a portion of the 
network costs, but rather must pay for the entire network, which 
integrates all of the transmission-owning utility's resources and 
loads. According to AEP, the load served by behind-the-meter generation 
is not isolated from the system, which is there to serve that load when 
the behind-the-meter generation is unavailable. Allowing a network 
customer to use short-term non-firm point-to-point transmission, AEP 
asserts, allows customers to evade a large portion of the network's 
costs, which they will do on an unconstrained system such as AEP.

Commission Conclusion

    We disagree that the prohibition in tariff section 1.22 against a 
network customer designating only part of a load at a discrete point of 
delivery as network load is either inconsistent with the Final Rule's 
treatment of generation ``behind the meter'' or is contrary to the 
Commission's decisions in FMPA I and FMPA II.
    The Commission addressed ``behind the meter'' generation in the 
Final Rule as follows:

if a customer wishes to exclude a particular load at discrete points 
of delivery from its load ratio share of the allocated cost of the 
transmission provider's integrated system, it may do so. [citing 
Florida Municipal Power Agency v. Florida Power & Light Company, 74 
FERC para. 61,006 (1996), reh'g pending.] Customers that elect to do 
so, however, must seek alternative transmission service for any such 
load that has not been designated as network load for network 
service. This option is also available to customers with load served 
by 'behind the meter' generation that seek to eliminate the load 
from their network load ratio calculation.\241\
---------------------------------------------------------------------------

    \241\ FERC Stats. & Regs. at 31,736; mimeo at 297.

Implicit in the Commission's discussion of this issue in the Final Rule 
and also in FMPA I and FMPA II, in permitting

[[Page 12323]]

the ``exclusion of a particular load,'' is that the Commission will 
allow a network customer to exclude the entirety of a discrete load 
from network load, but not just a portion of the load served by 
generation behind the meter.
    In its request for rehearing of FMPA I, FMPA requested that the 
Commission confirm its interpretation of the Commission's finding in 
FMPA I that:

[FMPA] can choose to serve an amount of load in a city from 
generation in the city, so long as FMPA does not sometimes serve 
that level of load from external generation or use that generation 
to serve member loads outside the city.\242\
---------------------------------------------------------------------------

    \242\ FMPA II at 61,012 (emphasis added).

On rehearing in FMPA II, the Commission did not grant FMPA's request to 
allow a partial designation of network load. Furthermore, the 
Commission provided an example of how FMPA could request that certain 
of its loads and resources be excluded from network integration 
transmission service. The Commission explained that FMPA could choose 
to exclude the loads of the cities of Ft. Pierce and Vero Beach from 
the request for network integrated transmission service and 
alternatively request point-to-point transmission service to transmit 
power from resources in those cities to other FMPA members or from FMPA 
member cities to Ft. Pierce and Vero Beach.\243\ The Commission neither 
stated that it would allow a partial designation of a discrete load as 
network load nor provided any examples of such treatment.
---------------------------------------------------------------------------

    \243\ FMPA II at 61,011.
---------------------------------------------------------------------------

    Additionally, throughout the pro forma tariff, network customers 
are consistently prohibited from designating only a portion of a 
discrete network load. For example, tariff section 31.2 provides:

    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. 
[Emphasis added]

Accordingly, we find that no inconsistency exists between the tariff 
language and either the language in the Final Rule or the Commission's 
findings in FMPA I or FMPA II.
    In support of its position to allow a partial designation of 
network load at a point of delivery, TAPS claims that there are no 
operational reasons to require the designation of all load at a 
discrete point of delivery as network load. We disagree. Utilities, 
both commenting on the NOPR and on rehearing (e.g., AEP rehearing at 
19-20 and Florida Power & Light at 14-18), express concern that 
customers allowed to divide a discrete load between point-to-point and 
network services would create a ``split system.'' The concept of 
allowing a ``split system'' or splitting a discrete load is 
antithetical to the concept of network service. A request for network 
service is a request for the integration of a customer's resources and 
loads. Quite simply, a load at a discrete point of delivery cannot be 
partially integrated--it is either fully integrated or not integrated. 
Furthermore, such a split system creates the potential for a customer 
to ``game the system'' thereby evading some or all of its load-ratio 
cost responsibility for network services.\244\
---------------------------------------------------------------------------

    \244\ The load-ratio cost responsibility is based on the network 
customer's monthly contribution to the transmission system peak 
(i.e., coincident peak billing).
---------------------------------------------------------------------------

    For example, FMPA asserts that if a FMPA member city has a peak 
load of 100 MW and behind the meter generation of 75 MW, FMPA should be 
allowed to designate a portion of its load as network load (e.g., 60 
MW), and to serve the remaining load (e.g., 40 MW) from its behind-the-
meter generation.\245\ However, as a number of utilities note, this 
would lead to the possibility of gaming the system. For example, if at 
the time of the monthly system peak the FMPA member city generates more 
than 40 MW (or takes short-term firm transmission service (or a 
combination of the two)), it may be able to lower its monthly 
coincident peak load for network billing purposes,\246\ and thereby 
reducing if not eliminating its load-ratio cost responsibility for 
network service. Because network and native load customers bear any 
residual system costs on a load-ratio basis, any cost responsibility 
evaded by a network customer in this manner would be borne by the 
remaining network customers and native load.
---------------------------------------------------------------------------

    \245\ FMPA at 3-4.
    \246\ While this customer could lower its coincident peak use of 
the transmission system, it could be making substantial use of the 
transmission system during all other hours of the month but yet have 
little or no load-ratio cost responsibility.
---------------------------------------------------------------------------

    FPL also raises several fundamental operational problems associated 
with allowing partial network service or creating a ``split system:''

    If all the loads are included in a single control area, how does 
the transmission provider know what portion of the power delivered 
is serving the point-to-point load (which presumably would not be 
counted toward the network's load ratio)?
    Using the same 100 MW load example previously mentioned where 
there is a 40/60 network/point-to-point split, there would have to 
be a determination of how the split would be done in non-peak 
situations. Are the first 40 MW of load all network load, or all 
point-to-point load, or split on a 40/60 basis?
    If the system purchases economy power from non-local resources, 
how is that delivery allocated between the network portion (for 
which there would be no point-to-point scheduling, curtailment, or 
transmission charges) and the point-to-point portion (which must be 
arranged and paid for separately under a point-to-point tariff)?

    The bottom line is that all potential transmission customers, 
including those with generation behind the meter, must choose between 
network integration transmission service or point-to-point transmission 
service. Each of these services has its own advantages and risks.\247\
---------------------------------------------------------------------------

    \247\ Customers taking network integration transmission service 
choose to have the transmission provider integrate their generation 
resources with their loads. Network service is a service comparable 
to the service that the transmission provider provides to its retail 
native load, where the Transmission Provider includes the network 
customers resources and loads (projected over a minimum ten-year 
period) into its long-term planning horizon. Because network service 
is usage based, network customers pay on the basis of their total 
load, paying a load-ratio share of the costs of the transmission 
provider's transmission system on an ongoing basis. In contrast, 
point-to-point transmission service is more transitory in nature. 
Point-to-point service is frequently tailored for discrete 
transactions for various time periods, which may or may not enter 
into the transmission provider's planning horizon. A point-to-point 
transmission service customer is only responsible for paying for its 
reserved capacity on a contract demand basis over the contract term.
---------------------------------------------------------------------------

    In choosing between network and point-to-point transmission 
services, the potential customer must assess the degree of risk that it 
is willing to accept associated with the availability of firm 
transmission capacity. Customers choosing point-to-point service, based 
solely on the amount of transmission capacity reserved (or contract 
demand), may face a relatively higher risk associated with the 
availability of firm transmission capacity. For example, if a customer 
with a peak load of 100 MW, and behind the meter generation of 75 MW, 
chooses to serve a portion of its load with point-to-point transmission 
service (e.g., 60 MW) and the remaining load (e.g., 40 MW) with its 
behind-the-meter generation, this customer faces the risk that, should 
its generation behind the meter become unavailable, the transmission 
provider may not have firm transmission capacity available to serve the 
remaining 40 MW of that

[[Page 12324]]

customer's load. One way to minimize this risk would be for the 
customer to reserve and pay for additional firm point-to-point 
transmission service to protect against the unavailability of its 
behind-the-meter generation. Alternatively, the customer could choose 
network service in which the transmission provider will plan and 
provide for firm transmission capacity sufficient to meet the 
customer's current and projected peak loads, including integration of 
the customer's behind-the-meter generation as a network resource.
    For the reasons stated above, a network customer will not be 
permitted to take a combination of both network and point-to-point 
transmission services under the pro forma tariff to serve the same 
discrete load. Accordingly, the requests for rehearing to modify tariff 
section 1.22 are hereby rejected.
    Moreover, the Commission will allow a network customer to either 
designate all of a discrete load \248\ as network load under the 
network integration transmission service or to exclude the entirety of 
a discrete load from network service and serve such load with the 
customer's ``behind-the-meter'' generation and/or through any point-to-
point transmission service.<SUP>249
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    \248\ We also clarify that while the tariff prohibits the 
designation of only part of the load at a discrete point of 
delivery, this prohibition also applies to network customers with a 
discrete load served by multiple points of delivery. In other words, 
for the same reasons explained above, a customer may not choose to 
have part of a discrete load served under network integration 
service at one or more delivery points and at the same time have the 
remaining portion of the same load served under point-to-point 
transmission service at other delivery points.
    \249\ An example of excluding the entirety of a discrete load 
would be a municipal power agency excluding the entire load of a 
member city with generation behind the meter, while requesting 
network service to serve the remaining member cities' loads. The 
excluded load of the member city must be met using a combination of 
generation behind the meter and any remote generation that may be 
necessary. The member city would be responsible for arranging any 
point-to-point transmission service under the pro forma tariff that 
may be necessary to import the power and energy from any remote 
generation.
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(4) Existing Transmission Arrangements associated with Generating 
Capacity Entitlements (e.g., ``preference power'' customers of PMAs)

Rehearing Requests

    Several entities argue that section 1.22 of the pro forma tariff is 
arbitrary and cannot be reconciled with the Final Rule's determination 
not to abrogate existing agreements. \250\
---------------------------------------------------------------------------

    \250\ E.g., NRECA, TDU Systems, AEC & SMEPA.
---------------------------------------------------------------------------

    Specifically, several transmission customers claim that the 
prohibition against designating only part of the load at a discrete 
point of delivery is problematic for customers with existing 
transmission arrangements for receiving preference power or capacity 
entitlements from power marketing agencies (PMAs). For example, Central 
Minnesota Municipal argues that the limiting language of section 1.22 
should be eliminated as it would preclude Mountain Lake (a member of 
Central Minnesota Municipal) from using network transmission and, at 
the same time, point-to-point transmission for WAPA power under a 
separate arrangement. These transmission customers assert that if they 
designate all of the load at a discrete point of delivery as network 
load, and pay for such network load on a load-ratio basis, then the 
transmission provider is paid twice for the same transmission service--
once through the existing transmission arrangement and a second time 
through the network service.
    NRECA and TDU Systems argue that if a customer chooses to use 
network service under the pro forma tariff to supplement its existing 
arrangements to meet future full requirements, the Commission should 
amend section 1.22 so the transmission provider cannot overcharge the 
customer:

    A Network Customer may elect to designate less than its total 
load as Network Load. Where a Network Customer has elected not to 
designate a particular load as a Network Load, the Network 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, unless such non-designated 
load is served pursuant to other arrangements. <SUP>[251]

    \251\ NRECA at 78-79; TDU Systems at 32.
---------------------------------------------------------------------------

    Alternatively, the transmission customer may choose not to 
designate any load at a discrete point of delivery as network load. 
However, these transmission customers note that the preference power 
allotments received from PMAs typically do not equal the total load of 
a customer at a discrete point of delivery. Therefore, the customer 
would need to acquire additional point-to-point transmission service 
for any remaining transmission needs. Accordingly, these transmission 
customers conclude that the existence of their current transmission 
arrangements precludes them from receiving network service which they 
claim does not allow the comparable use of the system that the 
transmission provider enjoys.

Commission Conclusion

    The Commission recognizes that existing power and transmission 
arrangements represent a transitional problem as customers begin to 
take service under the pro forma tariff. Clearly, the Commission did 
not intend for a transmission provider to receive two payments for 
providing service to the same portion of a transmission customer's 
load. Any such double recovery is unacceptable and inconsistent with 
cost causation principles. Neither did the Commission intend to allow a 
transmission customer to designate less than its total load as network 
load at a discrete point of delivery even though a portion of that load 
is served under a pre-existing contract. We clarify that such a 
transmission customer has several alternatives it can pursue using 
either point-to-point or network transmission service.
    Using network transmission service, the network customer would 
designate its existing generation supply contract(s) as a network 
resource(s) and the associated load served under such contract(s) 
designated as network load. The network customer then has two options: 
pursue negotiations with the transmission provider to obtain a credit 
on its network service bill for any separate transmission arrangements 
or for the unbundled transmission rate component of the existing 
generation supply contract or (2) seek to have any separate 
transmission or the unbundled transmission rate component of its 
generation supply contract eliminated in recognition of the network 
transmission service now being provided and paid for under the 
tariff.<SUP>252
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    \252 Clearly, any such modification of existing contracts would required the agreement of all parties and a filing with the Commission.\

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    Using point-to-point transmission service, the transmission 
customer would identify the discrete points of delivery being served 
under existing generation supply and existing transmission contracts 
and acquire additional point-to-point transmission service under the 
tariff for any remaining load at those discrete points of delivery.
    Any of these three alternatives should address concerns regarding 
the possibility of double recovery. Furthermore, a transmission 
customer may file a complaint under section 206 with the Commission to 
address any claims of double recovery that it is unable to resolve with 
the transmission provider.
d. Annual System Peak Pricing for Flexible Point-to-Point Service
    In the Final Rule, the Commission indicated that it will allow a 
transmission provider to propose a formula rate that assigns costs

[[Page 12325]]

consistently to firm point-to-point and network services.<SUP>253 The 
Commission added that it will no longer summarily reject a firm point-
to-point transmission rate developed by using the average of the 12 
monthly system peaks.
---------------------------------------------------------------------------

    \253\ FERC Stats. & Regs. at 31,737-38; mimeo at 301-04.
---------------------------------------------------------------------------

    The Commission explained that it still believed that it was 
appropriate for utilities to use a customer-specific allocated cost of 
service to account for diversity, but based on the changed 
circumstances since Southern Company Services, Inc., 61 FERC para. 
61,339 (1992) (Southern), it indicated that it would now permit an 
alternative. Thus, the Commission indicated that it will allow all firm 
transmission rates, including those for flexible point-to-point 
service, to be based on adjusted system monthly peak loads.
    In order to prevent over-recovery of costs for those who use this 
approach, the Commission explained that it will require transmission 
providers to include firm point-to-point capacity reservations in the 
derivation of their load ratio calculations for billings under network 
service. In addition, the Commission explained that revenue from non-
firm transmission services should continue to be reflected as a revenue 
credit in the derivation of firm transmission tariff rates. The 
Commission noted that the combination of allocating costs to firm 
point-to-point service and the use of a revenue credit for non-firm 
transmission service will satisfy the requirements of a conforming rate 
proposal enunciated in our Transmission Pricing Policy 
Statement.<SUP>254
---------------------------------------------------------------------------

    \254\ FERC Stats. & Regs. para. 31,005 (1994).
---------------------------------------------------------------------------

Rehearing Requests

    Blue Ridge maintains:

    The sea change in the Commission's approach to the pricing of 
transmission services is not warranted by any claimed change in 
circumstances and Blue Ridge accordingly requests rehearing and 
rejection of the new approach. At a minimum, the Commission should 
clarify that any deviation from use of an annual peak divisor (or 
other methodology based on system capability) for setting point-to-
point transmission rates will be considered only on a case-by-case 
basis.

    TAPS also argues that the use of the same denominator for two 
different services is inconsistent, unjust and discriminatory. It 
asserts that the Commission should use a system capability divisor for 
allocating fixed costs between reservation-based and load-based firm 
service.
    TAPS also asserts that most utilities plan their transmission 
systems to cover the annual system peak estimated conservatively on the 
higher side in order to meet unusually high loads reliably, rather than 
planning on the basis of the twelve monthly peaks as stated in Order 
No. 888. Therefore, TAPS asks that the Commission maintain 1 CP pricing 
for point-to-point service. TAPS argues that the Commission should 
allow transmission providers and customers to demonstrate the 
appropriate measure for each transmission system's capability in 
utility-specific proceedings.
    If the Commission uses a 12 CP denominator, TAPS requests that the 
Commission clarify that capacity reservations should be established 
consistently with that denominator and should recognize the 
inappropriateness of using such rates as a cap for non-firm rates. It 
asserts that non-firm rates should be limited to actual variable costs 
of transmission, plus losses, plus a modest adder as a contribution 
toward fixed costs. At the very least, TAPS argues that the cap should 
be developed using a more appropriate denominator, e.g., system 
capability.
    TAPS further argues that if the rate divisor is based on 
experienced 12 CP, the capacity reservations and the divisor should be 
measured at the delivery points (as it is for native load customers), 
not the higher of the receipt or delivery points, to avoid a mismatch 
between the rate divisor and billing determinants.<SUP>255
---------------------------------------------------------------------------

    \255\ See also NE Public Power District.
---------------------------------------------------------------------------

    Wisconsin Municipals and TAPS argue that if a 12 CP divisor is 
used, customers must have the flexibility to vary their monthly 
nomination under the point-to-point tariff.

Commission Conclusion

    With respect to TAPS argument that the annual system peak method 
would be appropriate for most systems, the Commission has determined in 
Order No. 888 that this issue is best resolved on a case-by-case basis 
and specifically provided utilities the opportunity to propose to use 
other allocation methods, including the annual system peak method 
sought by TAPS.<SUP>256
---------------------------------------------------------------------------

    \256\ FERC Stats. & Regs. at 31,736; mimeo at 296-97.
---------------------------------------------------------------------------

    The Commission already recognized the potential for a mismatch 
between the rate divisor and billing determinants that TAPS now raises 
on rehearing. We explicitly stated in the Final Rule that

[t]he adjusted system monthly peak loads consist of the transmission 
provider's total monthly firm peak load minus the monthly coincident 
peaks associated with all firm point-to-point service customers plus 
the monthly contract demand reservations for all firm point-to-point 
service.<SUP>[257]
---------------------------------------------------------------------------

    \257\ FERC Stats. & Regs. at 31,738; mimeo at 303.
---------------------------------------------------------------------------

    Use of the adjusted system monthly peak loads in the rate divisor 
for flexible point-to-point transmission service eliminates the 
mismatch concern raised by TAPS.
    We have also fully addressed in the Final Rule those arguments 
objecting to the use of the average of the 12 monthly peaks in 
determining a firm point-to-point transmission rate and no further 
discussion is required. The other arguments raised with respect to this 
section are fact specific and best addressed in individual rate 
proceedings where the use of an annual system peak versus an average of 
the 12 monthly peaks in determining a firm point-to-point transmission 
rate is more appropriately evaluated.
e. Opportunity Cost Pricing
(1) Recovery of Opportunity Costs
    The Commission emphasized in the Final Rule that it had fully 
explained its rationale for allowing utilities to charge opportunity 
costs in Northeast Utilities and Penelec.<SUP>258 The Commission also 
explained that transmission providers proposing to recover opportunity 
costs must adhere to the following requirements:
---------------------------------------------------------------------------

    \258\ Northeast Utilities Service Company (Northeast Utilities), 
56 FERC para. 61,269 (1991), order on reh'g, 58 FERC para. 61,070, 
reh'g denied, 59 FERC para. 61,042 (1992), order granting motion to 
vacate and dismissing request for rehearing, 59 FERC para. 61,089 
(1992), aff'd in relevant part and remanded in part, Northeast 
Utilities Service Company v. FERC, 993 F.2d 937 (1st Cir. 1993); 
Pennsylvania Electric Company (Penelec), 58 FERC para. 61,278 at 
62,871-75, reh'g denied, 60 FERC para. 61,034 (1992), aff'd, 
Pennsylvania Electric Company v. FERC, 11 F.3d 207 (D.C. Cir. 1993).
---------------------------------------------------------------------------

    (1) A fully developed formula describing the derivation of 
opportunity costs must be attached as an appendix to their proposed 
tariff;
    (2) Proposals must address how they will be consistent with 
comparability; and
    (3) All information necessary to calculate and verify opportunity 
costs must be made available to the transmission customer.

Rehearing Requests

    VT DPS disputes the Commission's holding with respect to 
opportunity costs and argues that rate filings seeking recovery of 
opportunity costs should be summarily rejected. It asserts that, 
contrary to statements by the Commission, courts have not endorsed 
opportunity cost pricing for transmission customers and maintains that 
the Commission's failure to consider objections to opportunity cost

[[Page 12326]]

pricing on the merits ``directly flouts the court's ruling'' in 
Northeast Utilities. According to VT DPS, opportunity costs are 
inherently unverifiable: ``there are insuperable difficulties in 
proving the existence of lost opportunity costs in any fashion which 
can readily and objectively be applied.'' At a minimum, VT DPS asserts, 
opportunity costs arising more than five years out are unverifiable and 
should not be permitted. Moreover, VT DPS argues that the right to 
challenge the verifiability of opportunity costs is not adequate 
protection because it is wasteful and burdensome (citing Cajun Electric 
Power Cooperative v. FERC, 28 F.3d 173 at 179 (D.C. Cir. 1994) 
(Cajun)).
    VT DPS also asserts that the Commission's treatment is inconsistent 
with its treatment of gas pipeline pricing policies, which do not 
permit the assessment of opportunity costs in gas pipeline 
transportation rates. In addition, VT DPS asserts that opportunity cost 
pricing for firm transportation service would allow the transmitting 
utility to charge more for firm transmission of a third party's power 
supplies than it charges its own native load for the transmission 
component of native load service. Finally, VT DPS claims that 
opportunity cost pricing contravenes Cajun because opportunity cost 
pricing has a chilling effect on competition in New England and 
nationally. VT DPS challenges whether a tariff provision that permits 
the imposition of opportunity costs ``precludes the mitigation of [a 
utility's] market power.''
    CCEM asserts that there is no justification for allowing 
opportunity cost charges when such charges can be eliminated in the 
secondary or released capacity market, without the discriminatory 
charge. It notes that opportunity costs are not allowed in any other 
industry and the Commission should not allow recovery of lost profits.
    American Forest & Paper argues that the only way to ensure 
comparability is to require that transmission services are priced for 
all customers based upon embedded cost principles (including pricing 
for expansions). It opposes opportunity cost pricing as being 
discriminatory because wheeling customers are required to compensate 
the transmitting utility for its lost opportunities to make economy 
purchases or sales to benefit native load. It further argues that 
transmission capacity was not designed to facilitate non-firm, 
unplanned economy purchases or sales on behalf of native load. American 
Forest & Paper also asserts that allowing redispatch costs incorrectly 
presupposes that native load has a superior right to the transmission 
system. According to American Forest & Paper, neither of these costs 
(opportunity/redispatch) should be imposed on the former sales, now 
transmission-only, customers--the transmission customer is no more 
responsible for the alleged transmission constraint than the existing 
native load customer who adds to its requirements or the new customer 
locating in the service territory. It maintains that firm transmission 
contracts cannot by definition displace opportunity sales because there 
is no ``opportunity'' until there is capacity in excess of the firm 
transmission contractual commitments. In addition, American Forest & 
Paper asserts that opportunity cost pricing may create difficulties for 
IPPs, i.e., a lender may not finance projects because of cost 
uncertainty related to varying revenue flows caused by opportunity cost 
pricing. It believes that utilities should be required to establish a 
separate subsidiary to make opportunity purchases or sales on its 
behalf, which may minimize self dealing.<SUP>259 It further asserts 
that expansions should be subject to embedded cost pricing--unlike in 
gas pipeline expansions, electric transmission expansions invariably 
affect an integrated network.
---------------------------------------------------------------------------

    \259\ The Commission has effectively achieved this result for 
opportunity sales by requiring separation of the transmission 
provider's wholesale merchant from its transmission operation 
employees.
---------------------------------------------------------------------------

    CCEM asserts that, if opportunity cost pricing is maintained, 
transmission customers should be given the information they need to 
avert or mitigate opportunity-cost exposure. In particular, it argues 
that customers need information on the run status and cost of 
generating units that the transmission provider controls in advance of 
any proposed redispatch. In addition, CCEM argues that transmission 
providers should be required to inform customers of a redispatch in 
advance.

Commission Conclusion

    As an initial matter, many of the arguments raised are collateral 
attacks on Penelec, Northeast Utilities, and the Commission's 
Transmission Pricing Policy Statement. These matters are not the 
subject of this proceeding, but rather Order No. 888 simply applies the 
policy already in place. Therefore, these arguments are not properly 
raised in this proceeding.<SUP>260
---------------------------------------------------------------------------

    \260\ These arguments include those made by VT DPS concerning 
Northeast Utilities and alleged inconsistencies with our natural gas 
policies.
---------------------------------------------------------------------------

    The Commission does not believe that any changes are necessary to 
its policy on opportunity cost recovery.<SUP>261 In the Final Rule, we 
fully explained our rationale for allowing utilities to charge 
opportunity costs and no arguments have been presented on rehearing 
that would persuade us otherwise.
---------------------------------------------------------------------------

    \261\ Under the Commission's transmission pricing policy, 
utilities are limited to charging the higher of embedded costs or 
opportunity/incremental costs. See Order on Reconsideration and 
Clarifying Policy Statement, 71 FERC para. 61,195 (1995). 
Opportunity costs are capped by incremental expansion costs. 
Opportunity costs are viewed as a form of incremental or marginal 
cost pricing and include: (1) out-of-rate costs or costs associated 
with the uneconomic dispatch of generating units necessary to 
accommodate a transaction; and (2) costs that arise from a utility 
having to reduce its off-system purchases or sales in order to avoid 
a potential constraint on the transmission grid. We note that Order 
No. 888 requires that off-system sales by the transmission provider 
must be made under the point-to-point provisions of the pro forma 
tariff.
    If a utility expands its transmission system so that it can 
provide the requested transmission service, it can charge the higher 
of its embedded costs or its incremental expansion costs. When a 
transmission grid is constrained and a utility does not expand its 
system, the Commission has allowed a utility to charge transmission-
only customers the higher of embedded costs or legitimate and 
verifiable opportunity costs (``or'' pricing), but not the sum of 
the two (``and'' pricing).
---------------------------------------------------------------------------

    As has been our policy, we will continue to determine the 
appropriateness of opportunity cost pricing proposals on a case-by-case 
basis. We continue to believe that opportunity cost pricing will 
promote efficient decision-making by both transmission owners and users 
and will not result in unduly discriminatory or anticompetitive 
pricing. We have stated that because any transmission pricing proposal 
must meet the comparability standard, we will have ample opportunity to 
address any concerns that opportunity cost pricing may be unfair and 
anticompetitive or otherwise inconsistent with the comparability 
standard, including those concerns raised by CCEM with respect to the 
need for advance information as to any proposed redispatch.
    We note that in compliance filings made pursuant to Order No. 888, 
most utilities did not make the tariff changes necessary to charge 
opportunity costs to customers under the pro forma tariff. Absent a 
subsequent section 205 filing, these transmission providers will not be 
able to charge opportunity costs under their compliance tariffs. Where 
transmission providers did modify their tariff to allow for opportunity 
costs, the Commission is reviewing the proposed charges on a case-by-
case basis.
(2) Redispatch Costs
    In the Final Rule, the Commission clarified that redispatch is 
required only if it can be achieved while maintaining

[[Page 12327]]

reliable operation of the transmission system in accordance with 
prudent utility practice.<SUP>262
---------------------------------------------------------------------------

    \262\ FERC Stats. & Regs. at 31,739-40; mimeo at 307-09.
---------------------------------------------------------------------------

    The Commission further explained that the recovery of redispatch 
costs requires that: (1) a formal redispatch protocol be developed and 
made available to all customers; and (2) all information necessary to 
calculate redispatch costs be made available to the customer for audit. 
The Commission also noted that the rates proposed must meet the 
standards for conforming proposals in the Transmission Pricing Policy 
Statement.
    The Commission also explained in the Final Rule that if the 
transmission provider proposes to separately collect redispatch costs 
on a direct assignment basis from a specific transmission customer, the 
transmission provider must credit these revenues to the cost of fuel 
and purchased power expense included in its wholesale fuel adjustment 
clause.<SUP>263
---------------------------------------------------------------------------

    \263\ FERC Stats. & Regs. at 31,740; mimeo at 309.
---------------------------------------------------------------------------

Rehearing Requests

    TAPS asserts that there is too much uncertainty with respect to the 
treatment of redispatch costs. It asserts that the Commission should 
require a section 205 filing for each corridor/constraint for which 
redispatch costs are intended to be shared among the transmission 
provider and network customers. Once there has been a determination 
regarding a particular corridor/constraint, TAPS argues that ``it would 
be appropriate to charge network customers for redispatch costs through 
a mechanism with no fewer protections than a fuel clause.'' It further 
argues that redispatch costs, like opportunity costs, should be capped 
at the cost of the upgrade and, at the least, the Commission should 
clarify that application of the redispatch sharing provision should be 
adjudicated in particular cases.
    TDU Systems states that it does not object to a redispatch 
obligation that is necessary to ensure transmission system reliability, 
but they object to the fact that a transmission provider can determine 
that a transmission constraint will arise as a result of the sale of 
additional firm transmission service by the transmission provider. It 
asks the Commission to clarify that the transmission constraint that 
would trigger a redispatch obligation cannot be caused by a 
transmission provider's sale of additional firm transmission 
capability.
    Wisconsin Municipals asks the Commission to clarify that recovery 
of redispatch costs on a load ratio basis, without a section 205 
filing, is limited to when such action is necessary for reliability 
reasons alone (not for economic reasons), and that in all other 
circumstances a section 205 filing must be made and costs directly 
assigned to the customer receiving the economic benefit of the 
redispatch. It further asserts that if redispatch is allowed for 
economic reasons, it must be offered on a comparable, non-
discriminatory basis to all customers and the transmission provider, 
provided the beneficiary agrees to accept a direct assignment.
    Several utilities argue that redispatch costs are a subset of 
opportunity costs and that the Commission should not use both terms in 
the tariff because it implies different standards apply to transmission 
providers and their customers (e.g., sections 23.1 and 27).<SUP>264 
They request that the Commission only use the term ``redispatch costs'' 
in the pro forma tariff and impose the same redispatch obligations on 
network customers as are imposed on transmission providers.
---------------------------------------------------------------------------

    \264\ E.g., Utilities For Improved Transition, Florida Power 
Corp, VEPCO.
---------------------------------------------------------------------------

    No rehearing requests addressed the subject of fuel adjustment 
clause treatment for redispatch costs.

Commission Conclusion

    The Commission believes that the obligation to create additional 
transmission capacity to accommodate a request for firm transmission 
service should properly lie with the transmission provider, not a 
network customer.
    The Commission clearly established in the Final Rule that utilities 
are to be given ``substantial flexibility * * * to propose appropriate 
pricing terms, including opportunity cost pricing [of which redispatch 
costs are a subset], in their compliance tariff.'' <SUP>265 The 
Commission further required that any such rate proposals must meet the 
standards for conforming proposals in the Transmission Pricing Policy 
Statement. Accordingly, TAPS is free to pursue its concerns in any 
relevant compliance filings.
---------------------------------------------------------------------------

    \265\ FERC Stats. & Regs. at 31,739; mimeo at 307-08.
---------------------------------------------------------------------------

    Tariff sections 33.2 and 33.3 clearly establish that redispatch of 
all Network Resources and the transmission provider's own resources are 
only to be performed to maintain the reliability of the transmission 
system, not for economic reasons. Such costs are to be shared between 
network customers and the transmission provider on a load ratio basis. 
Similarly, the Commission clarified in Order No. 888, in modifying the 
transmission customer's redispatch obligation, that such change was 
``to limit the redispatch obligation to reliability reasons.'' <SUP>266 
Therefore, no further clarification is necessary.
---------------------------------------------------------------------------

    \266\ FERC Stats. & Regs. at 31,767; mimeo at 388.
---------------------------------------------------------------------------

    Other redispatching provisions under the tariff (e.g., sections 
13.5 and 27) refer to situations where the transmission provider can 
relieve a system constraint more economically by redispatching the 
transmission provider's resources than through constructing Network 
Upgrades in order to provide the requested transmission service. 
However, in this circumstance, redispatch is conditioned upon the 
eligible customer agreeing to compensate the transmission provider for 
such redispatch costs. Section 13.5 of the pro forma tariff further 
requires that any such redispatch costs to be charged to the 
transmission customer on an incremental basis must be specified in the 
customer's service agreement prior to initiating service. These tariff 
requirements would appear to satisfy Wisconsin Municipals concerns 
because a section 205 filing must be made to directly assign costs to 
the customer receiving the economic benefit of the redispatch.
    Regarding the argument that only the term ``redispatch costs'' 
should be used in the pro forma tariff, we note that the Commission 
followed this suggestion in drafting the pro forma tariff. The only 
exception is the use of opportunity costs in section 23.1 of the 
tariff, which caps the compensation for resellers at the higher of: (1) 
the original rate, (2) the transmission provider's maximum rate on file 
at the time of the assignment or (3) the reseller's opportunity cost. 
We further note that their concerns that different standards may be 
applied to transmission providers than to their customers are addressed 
in section IV.C.6 (Capacity Reassignment).
f. Expansion Costs
    In the Final Rule, the Commission allowed transmission providers to 
propose any method of collecting expansion costs that is consistent 
with the Commission's transmission pricing policy.<SUP>267 The 
Commission explained that ``or'' pricing sends the proper price signal 
to customers and promotes efficiency and further indicated that ``and'' 
pricing will not be allowed.
---------------------------------------------------------------------------

    \267\ FERC Stats. & Regs. at 31,741; mimeo at 312-13.
---------------------------------------------------------------------------

    The Commission also indicated that any request to recover future 
expansion

[[Page 12328]]

costs will require a separate section 205 filing.

Rehearing Requests

    Several entities argue that requiring section 205 filings for all 
transmission expansion costs would impose difficult burdens on 
transmission providers that use formula rates because they would have 
to try to distinguish between replacement costs, which are included in 
formula rates, and expansion costs, which are not.<SUP>268 They assert 
that section 205 filings should be required only for system expansion 
costs that the transmission provider proposes to recover on a direct 
assignment or incremental cost basis, but not for costs to be recovered 
on an embedded cost basis.
---------------------------------------------------------------------------

    \268\ E.g., Utilities For Improved Transition, Florida Power 
Corp, VEPCO.
---------------------------------------------------------------------------

    TDU Systems maintain that to the extent Order No. 888's provisions 
concerning direct assignment of transmission facilities indicate a 
change in the historic policy of rolling transmission investments into 
rate base, there is a risk TDUs will bear a disproportionate share of 
the transmission burden relative to transmission owners under the 
Commission's ``or'' pricing policy. According to TDU Systems, 
transmission owners should be required to permit customers to 
substitute their own lower cost capital for that of the owner's.
    SoCal Edison and Carolina P&L ask the Commission to clarify that a 
transmission provider has no obligation to build or upgrade its 
facilities for short-term firm point-to-point transmission customers 
(Secs. 13.5, 15.4 and 1.13). SoCal Edison states that if a transmission 
provider is required to build, the Commission should clarify that any 
costs must be directly assigned to the requesting customer.

Commission Conclusion

    The Final Rule does not change the Commission's filing requirements 
for recovery of transmission expansion costs or other transmission-
related expenses. The Rule does not impose a section 205 filing 
requirement to the extent that existing formula rates do not require 
that such a filing be made to add transmission investment. However, 
consistent with the Commission's transmission pricing principles in 
effect prior to Order No. 888, a decision to price transmission on an 
incremental cost basis, or to directly assign facilities, are cost 
assignments that require a section 205 filing.
    The Final Rule also does not change the Commission's transmission 
pricing policies. Under our transmission pricing policy, a utility is 
still permitted to charge the higher of incremental expansion costs 
``or'' a rolled-in embedded cost rate. There is no bias in the Final 
Rule that should cause TDU customers or any other customer to pay a 
disproportionate share of transmission costs. Moreover, we note that we 
also encourage joint planning/building options and regional solutions 
such as RTGs and ISOs.
    We do not believe that any change is necessary with regard to the 
obligation to build or expand. While both sections 13.5 and 15.4 
obligate the transmission provider to expand or upgrade its 
transmission system to accommodate an application for firm point-to-
point transmission service, these sections are conditioned upon the 
transmission customer agreeing to compensate the transmission provider 
for such upgrade. In light of this compensation requirement, we do not 
anticipate that transmission providers will be requested to upgrade 
facilities in order to accommodate requests for short-term point-to-
point transmission service. However, in the unlikely event that a 
short-term firm point-to-point transmission customer agrees to pay the 
costs of such upgrades, we believe that it is appropriate to require a 
transmission provider to expand its system to accommodate the request.
g. Credit for Customers' Transmission Facilities
    In the Final Rule, the Commission concluded that credits related to 
customer-owned facilities are more appropriately addressed on a case-
by-case basis, where individual claims for credits may be evaluated 
against a specific set of facts.<SUP>269 The Commission stressed that 
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 to such a credit. The Commission further 
explained that it must be demonstrated that a transmission customer's 
transmission facilities are integrated with the transmission system of 
the transmission provider in order to establish a right to credits. The 
Commission also noted that consistent with its ruling in FMPA 
II,<SUP>270 if a customer wishes not to integrate certain loads and 
resources, and thereby exclude them from its load ratio share of the 
allocated cost of the integrated system, it may do so by separately 
contracting for point-to-point transmission service.
---------------------------------------------------------------------------

    \269\ FERC Stats. & Regs. at 31,742-43; mimeo at 316-18.
    \270\ Florida Municipal Power Agency v. Florida Power & Light 
Company, 74 FERC para. 61,006 (1996), reh'g pending.
---------------------------------------------------------------------------

Rehearing Requests

    APPA asserts that several differences between the treatment of 
transmission customers' and transmission providers' facilities are not 
comparable and must be corrected: (1) transmission providers' 
facilities include those owned, controlled or operated by the 
transmission provider, but to obtain credit, transmission customers 
must own the facilities; (2) transmission providers are under no 
obligation to engage in joint planning and historically have refused, 
thus putting the matter beyond the control of the customer; and (3) 
facilities of the customer must serve all of the transmission 
provider's power and transmission customers, but a transmission 
provider can include facilities in rates that serve only certain 
customers. APPA also maintains that the Commission failed to provide 
sufficient guidance to allow customers to ascertain the type of 
transmission facilities for which they can expect to receive credit.
    Several entities assert that the standard as to existing customer-
owned facilities is inherently ambiguous--the Final Rule preamble says 
integrated into the ``plans or operations'' of the transmitting 
utility, but section 30.9 of the tariff says the ``planning and 
operations'' of the transmission provider (emphasis added).<SUP>271 
Further, they assert, it is unreasonable to require, as a key to 
integration, that ``the transmission provider is able to provide 
transmission service to itself or other transmission customers over 
those facilities'' because it may be that the facilities are necessary 
to provide network service to the customer that owns the facilities and 
a credit would be appropriate. They argue that if transmission 
facilities serve load included in the network customer's network load, 
the transmission customer should get a credit.
---------------------------------------------------------------------------

    \271\ E.g., NRECA, Blue Ridge, TDU Systems.
---------------------------------------------------------------------------

    Blue Ridge states that ``[i]f the Commission does intend to change 
its standard or otherwise codify the result of FMPA II, then Blue Ridge 
urges rehearing and suggests a more analytical, policy oriented 
approach to the issue.'' (Blue Ridge at 31). It recommends adding the 
following language to the end of section 30.9 of the tariff concerning 
credit for new facilities: ``or if such facilities are integrated with, 
and support the

[[Page 12329]]

Transmission Provider's Transmission system.'' (Blue Ridge at 
Attachment 1).
    FMPA argues that a transmission provider can avoid paying credits 
for transmission that is functionally the same as that of the 
transmission provider simply by refusing to jointly plan. It asserts 
that the Commission should adopt either the Commission's integration 
test, without requiring joint planning, or a functionality test that 
considers whether the facilities of the customer and transmission 
provider are similar. Moreover, it argues that a more inclusive 
definition of the grid would better achieve comparability and 
competitive generation markets and would remove incentives to avoid 
joint planning. It argues that crediting customer-owned transmission 
also promotes the establishment of regional grids.
    Several entities state that the standard as to future network 
customer-owned facilities should be modified to make joint planning 
mandatory on the part of the transmission provider, who otherwise has 
little incentive to cooperate and coordinate.<SUP>272 They claim that 
in joint planning, plans cannot be developed by the transmission 
provider alone. They further argue that the Commission should not deem 
the lack of joint planning dispositive of the operation and planning 
issue.
---------------------------------------------------------------------------

    \272\ E.g., NRECA, TDU Systems, TAPS.
---------------------------------------------------------------------------

    TAPS asks the Commission to clarify that credits will be provided 
for existing, as well as future, facilities if the integration 
requirement is met.
    Wisconsin Municipals asks the Commission to clarify that the level 
of customer-owned credits is a rate issue and that if parties have 
negotiated provisions for credits, the Final Rule cannot be used by 
transmission providers to avoid the obligations undertaken in a 
settlement.
    NRECA and TDU Systems assert that the Commission should not abandon 
its historical practice of rolling in transmission facilities for 
purposes of transmission pricing; otherwise, the Commission must 
examine the function of all transmission facilities in a transmission 
provider's rate base and exclude them if they are not ``integrated'' 
(referencing Order No. 888 at 317 n.452). They argue that because 
customers would have to file section 206 filings to enforce this, the 
Commission should require transmission providers to file under section 
205 the identity of those facilities that will be included in the 
transmission rate base, those that will be excluded, and the supporting 
data.
    Turlock wants the Commission to provide concrete guidelines as to 
the eligibility of facilities for customer credits. Moreover, Turlock 
asserts that credits may be appropriate for point-to-point customers as 
well--especially in Northern California where PG&E, according to 
Turlock, encouraged customers to build facilities. Turlock finds this 
particularly important where PG&E has proposed to switch from 
subfunctionalized ratemaking to system-wide rolled-in ratemaking. It 
asserts that, if there are system-wide rolled in rates without a credit 
provision, there may be a violation of the ``or'' pricing policy.
    Several entities ask the Commission to clarify that the crediting 
provision works on a comparable basis for transmission customers and 
providers.<SUP>273 They ask the Commission to clarify that the phrase 
``serve all of its power and transmission customers'' in section 30.9 
is to be measured by the facilities that the transmission provider 
rolls into rate base to determine transmission rates and the 
transmission component of requirements rates. For example, they argue 
that because AEP rolls radial lines into rate base, comparable 
customer-owned lines should receive a credit. They also ask the 
Commission to clarify that the test that facilities are integrated into 
the planning and operations of the transmission provider is an 
objective standard that is satisfied by evidence that the transmission 
provider's load flow studies take into account the transmission 
customer's facilities. They assert that the standard should not be a 
subjective one that depends on whether the transmission provider says 
that it includes customer facilities in its planning and operations.
---------------------------------------------------------------------------

    \273\ E.g., IMPA, TAPS, AMP-Ohio, Michigan Systems.
---------------------------------------------------------------------------

    AMP-Ohio adds that the integration requirement should also be 
satisfied by evidence that the transmission provider includes costs in 
its rate base or transmission expenses that are associated with 
transmission facilities of utilities that it acquires. Michigan Systems 
also asks that the Commission clarify that the test in section 30.9 is 
a functional test and not whether the transmission owner says it is 
integrating its operations.
    Michigan Systems states that it has no objection to leaving 
determinations of credits to rate cases, as an abstract matter, but 
asserts that the Commission should make clear that it will not 
implement newly-filed tariffs in a way that imposes multiple or 
inconsistent charges for transmission in the interim. Otherwise, it 
asserts, transmission dependent utilities may be out of business if 
they must wait years to get credit for grid transmission they already 
own and that they must pay to finance. Michigan Systems also states 
that it would be illegal to require systems to pay for transmission by 
applying a load ratio share based on total loads when they have made 
investments under contracts for transmission to serve a portion of 
those loads.
    TAPS states that the Commission must define what it means by 
``integrated.'' TAPS asserts that the term should mean grid facilities 
used to integrate the network customer's resources and loads. It 
further asserts that the Commission should continue to use the test 
whether the facilities serve a comparable function. Unless a proper 
credit is provided, TAPS maintains, network customers could pay twice 
for transmission. TAPS adds that without proper crediting, the 
Commission cannot require load ratio pricing of network service.
    TAPS asks the Commission to clarify the method it will use to 
calculate the credit in individual cases and suggests that the 
Commission adopt the method TAPS proposed in its initial comments in 
this proceeding.
    With respect to joint ownership of transmission facilities or 
ownership of transmission facilities through a joint exercise of powers 
agency (JPA) or a Generation and Transmission Cooperative, TANC asks 
that the Commission provide for proportionate entitlement to a credit 
among those who have invested in, and are entitled to the use of, such 
facilities. TANC also argues that the credit should apply to facilities 
used to complete a transaction under the transmission provider's point-
to-point tariff. Further, TANC asserts that upon a showing that the 
facilities are integrated, the credit in section 30.9 should be 
mandatory and asks that the Commission provide guidance as to the 
method of either calculating or applying the credit.

Commission Conclusion

    The Commission reaffirms its finding in Order No. 888 that the 
question of credits for customer-owned facilities is best resolved on a 
fact-specific, case-by-case basis.<SUP>274 Accordingly, the Commission 
does not believe that the rehearing requests seeking specific guidance 
regarding various aspects of

[[Page 12330]]

customer credits are appropriate for resolution at this time.<SUP>275
---------------------------------------------------------------------------

    \274\ FERC Stats. & Regs. at 31,742; mimeo at 316.
    \275\ Wisconsin Municipals' argument with respect to prior 
settlements has been previously addressed in Section IV.D.1.c.(2) 
(Energy Imbalance Bandwidth).
---------------------------------------------------------------------------

    In order to conform the Final Rule preamble language with the 
tariff provisions of Order No. 888,<SUP>276 we will modify section 30.9 
of the pro forma tariff to provide that a customer may receive a credit 
for its own facilities if it demonstrates that ``its transmission 
facilities are integrated into the plans or operations (instead of 
``planning and operations'') of the transmission provider to serve its 
power and transmission customers.'' <SUP>277 The intent of section 30.9 
of the pro forma tariff is that, for a customer to be eligible for a 
credit, its facilities must not only be integrated with the 
transmission provider's system, but must also provide additional 
benefits to the transmission grid in terms of capability and 
reliability, and be relied upon for the coordinated operation of the 
grid. Indeed, in the Final Rule we explicitly stated that the fact that 
a transmission customer's facilities may be interconnected with a 
transmission provider's system does not prove that the two systems 
comprise an integrated whole such that the transmission provider is 
able to provide transmission service to itself or other transmission 
customers over these facilities.<SUP>278
---------------------------------------------------------------------------

    \276\ See FERC Stats. & Regs. at 31,742-43; mimeo at 316-17.
    \277\ As we noted in FMPA II, this fundamental cost allocation 
concept applies to the transmission provider as well. Just as the 
customer cannot secure credit for facilities not used by the 
transmission provider to provide service, the transmission provider 
cannot charge the customer for facilities not used to provide 
transmission service. 74 FERC para. 61,006 at 61,010 n.48 (1996).
    \278\ FERC Stats. & Regs. at 31,742-43; mimeo at 317.
---------------------------------------------------------------------------

    The Commission further stated in the Final Rule that where disputes 
over credits for customer-owned facilities arise, it encourages all 
parties not to seek formal resolution at the Commission, but to first 
pursue alternative dispute resolution. In this regard, the customer at 
the time it is requesting network service could also request that a 
study be undertaken by the company to analyze the impact and benefit of 
the customer's facilities provided to the integrated transmission 
network.
    We share the concern of APPA and others that transmission providers 
have not allowed transmission customers to participate in the planning 
process for new transmission projects. Allowing potential transmission 
customers the opportunity to participate in transmission projects is 
important in ensuring that regional transmission needs are met 
efficiently. One way of accomplishing this goal is through an RTG, ISO, 
or other regional entity that has an open planning process. Where such 
entities do not exist, we strongly encourage public utilities to hold 
an open season for all transmission expansion projects, including those 
in response to a service request, so that all entities in the region 
have an opportunity to identify their future needs and participate in 
the project.
    Finally, requests for the Commission to mandate joint-planning are 
addressed below in the discussion of section 1.12 of the pro forma 
tariff.
h. Ceiling Rate for Non-firm Point-to-Point Service
    In the Final Rule, the Commission stated that it is important to 
continue to allow pricing flexibility.<SUP>279 The Commission explained 
that, in accordance with its current policies, the rate for non-firm 
point-to-point transmission service may reflect opportunity costs. The 
Commission further explained that, if a utility chooses to adopt 
opportunity cost pricing, the non-firm rate is effectively capped by 
the availability of firm service and is not subject to a separately-
stated price cap. On the other hand, the Commission explained that, if 
a utility chooses not to adopt opportunity cost pricing, the non-firm 
rate is capped at the firm rate.
---------------------------------------------------------------------------

    \279\ FERC Stats. & Regs. at 31,743-44; mimeo at 319-20.
---------------------------------------------------------------------------

Rehearing Requests

    Duquesne asks the Commission to clarify that the phrase ``the non-
firm rate is capped at the firm rate'' does not mean that the 
Commission is deviating from its principles that non-firm transmission 
service must be priced in a manner that (i) reflects the 
interruptibility of the service, and (ii) is economically efficient.

Commission Conclusion

    With regard to Duquesne's request, we clarify that the firm 
transmission rate simply represents a maximum rate or price cap for 
non-firm transmission prices. We emphasize that non-firm transmission 
prices should reflect the interruptibility of the service and should 
promote efficient use of the transmission system, subject to this price 
cap. Accordingly, while in some circumstances non-firm transmission 
rates may be set at the firm transmission rate level, the Commission 
expects that non-firm transmission rates would, in most instances, be 
priced below the price cap.
i. Discounts
    In the Final Rule, the Commission stated that if a transmission 
provider offers a rate discount to its affiliate, or if the 
transmission provider attributes a discounted rate to its own wholesale 
transactions, the same discounted rate must also be offered at the same 
time to non-affiliates on the same transmission path and on all 
unconstrained transmission paths.<SUP>280 In addition, the Commission 
required that discounts from the maximum firm rate for the provider's 
own wholesale use or its affiliate's wholesale use must be transparent, 
readily understandable, and posted on the transmission provider's OASIS 
in advance so that all eligible customers have an equal opportunity to 
purchase non-firm transmission at the discounted rate.<SUP>281 Finally, 
the Commission explained that discounts offered to non-affiliates must 
be on a basis that is not unduly discriminatory and must be reported on 
the OASIS within 24 hours of when available transmission capability 
(ATC) is adjusted in response to the transaction.
---------------------------------------------------------------------------

    \280\ All offers or agreements to provide rate discounts to 
affiliates (including the Transmission Provider's wholesale 
merchant) on a particular path must be posted immediately on the 
OASIS and be available for a long enough period to allow non-
affiliates to obtain the same discounted service on that path and on 
other paths for which the transmission provider must provide the 
same discount. We modify below our requirement regarding which other 
paths must receive the same discount.
    \281\ The Commission also stated that the same requirements will 
apply to discounts for firm transmission service. The Commission 
added that if a transmission provider offers an affiliate a discount 
for ancillary services, or attributes a discounted ancillary service 
rate to its own transactions, it must offer at the same time the 
same discounted rate to all eligible customers. The Commission noted 
that discounted ancillary services rates must be posted on the OASIS 
pursuant to Part 37 of the Commission's regulations.
---------------------------------------------------------------------------

Rehearing Requests

Utility Position

    A number of utilities assert that the affiliate discounting 
provision is too broad.<SUP>282 SoCal Edison asserts that if the 
affiliate discounting provision is kept, the requirement to discount 
similarly for non-affiliates on unconstrained paths should be limited 
to offers on the same day only for new transmission services and only 
for the duration of the service offered to the affiliate.
---------------------------------------------------------------------------

    \282\ E.g., SoCal Edison, Entergy, Southwestern, PacifiCorp, 
Montana Power, AEP, Utilities For Improved Transition, EEI.
---------------------------------------------------------------------------

    Entergy and Southwestern assert that the Commission should change 
the discount language, which provides that

[[Page 12331]]

whenever the transmission provider offers a discount to an affiliate, 
or attributes a discount to its own transaction, it must offer a 
comparable discount to all similarly situated transmission customers. 
Southwestern believes that the Commission does not justify its 
different treatment of discounts to affiliates and discounts to non-
affiliates--section 205(b) of the FPA states that a public utility may 
not give any undue preference or advantage to any person. Southwestern 
also notes that for gas pipelines, the Commission required that 
affiliate discounts be available to similarly situated shippers (citing 
18 CFR 161.3(h)(1)).
    PacifiCorp suggests replacing the last sentence of section 
37.6(c)(3) of the OASIS regulations with the following sentence: ``With 
respect to any discount offered to its own power customers or its 
affiliates, the Transmission Provider must, at the same time, post on 
the OASIS an offer to provide the same discount to all Transmission 
Customers on the same transmission path and on all other unconstrained 
transmission paths parallel thereto for deliveries to the same Point of 
Delivery.'' It argues that the Commission's approach of requiring the 
same discount to all transmission customers on the same path and on all 
unconstrained transmission paths would discourage discounting, even 
when done to attract counter-wheeling to relieve constraints.<SUP>283
---------------------------------------------------------------------------

    \283\ See also Washington Water Power.
---------------------------------------------------------------------------

    Several utilities argue that the discount language should be 
changed to require only that the same discount be offered to all 
customers on the same path.<SUP>284 Otherwise, Montana Power asserts, 
transmission providers will be reluctant to offer discounts to its own 
marketers so as to protect revenues on other paths.
---------------------------------------------------------------------------

    \284\ E.g., Montana Power, Allegheny, Puget.
---------------------------------------------------------------------------

    AEP suggests that the discount language be changed to require that 
the discount be made available for all unconstrained paths terminating 
at the same interface.
    Illinois Power argues that the Commission should require discounts 
for equivalent (i.e., similarly situated) service requests, on the 
basis of location, term and time of service, which it asserts conforms 
to the Commission's standards for natural gas pipelines (citing 18 CFR 
161.3(h)). Otherwise, it asserts, the Commission's approach will result 
in inefficient use of scarce transmission capacity and thereby 
discourage efficient bulk power trading.
    VEPCO asserts that transmission providers must be given more 
flexibility to accommodate differences in regional wholesale markets 
and to maximize the movement of economical capacity and energy. It 
states that a transmission provider will provide discounts only if they 
are not detrimental to existing committed agreements or potential 
future revenue--revenue from additional sales must offset the decrease 
in revenues from making discounts. It suggests that preferential 
treatment can be reduced by the following constraints: (1) offer the 
same discount to all transmission requests to the same points of 
delivery for the same time, and (2) a discount should not apply to 
service already agreed to but not yet provided at that point. Utilities 
For Improved Transition adds the following constraint: evaluate request 
for discount on whether it would increase volume without reducing total 
revenues.<SUP>285 Florida Power Corp asserts that because 
communications regarding discounts must be posted on OASIS, 
preferential treatment would be readily apparent.
---------------------------------------------------------------------------

    \285\ See also Florida Power Corp.
---------------------------------------------------------------------------

    EEI states that the discount requirement has the potential to 
arbitrarily reduce the revenue that the transmission provider may be 
able to obtain over alternative paths that may be unconstrained, but of 
greater potential value than the path(s) identified as appropriate for 
discounting. It adds that the requirements for posting discounts should 
be the same regardless of affiliation and should be limited to the 
specific transmission path(s) discounted by the transmission provider.
    Carolina P&L argues that the Commission should permit selective 
discounting of non-firm transmission service on a posted-in-advance (on 
OASIS) basis that will not create a most favored nations situation 
merely because the transmission provider or an affiliate availed itself 
of the posted discount.

Customer Position

    Tallahassee asks the Commission to clarify that the transmission 
provider must automatically apply the discount to any eligible customer 
or, at the minimum, provide actual and timely notice of the discount's 
availability.
    Similarly, PA Coops asserts that ``[i]f transmission service is 
being discounted to any customer, affiliated or not, for a specific 
level of service at a specific point in time, it should be equally 
discounted to all customers receiving the same transmission service. To 
do otherwise is unduly discriminatory.'' (PA Coops at 11).
    TAPS asserts that all discounts must be posted in advance, the 
reasons for the discounts should be transparent, the transmission 
provider should keep all requests for discounts in a log, and short-
lived discounts should not be permitted.

Commission Conclusion

    In response to the arguments raised with respect to discounting, we 
will revise our policy on discounting transmission service. This 
revised policy will assure consistency with our standards of conduct 
requirements, which preclude a utility's wholesale merchant function 
from having access to its transmission system information (including 
price) not posted on the OASIS that is not otherwise also available to 
the general public or that is not also publicly available to all 
transmission users. The revised policy also should result in less 
opportunity for affiliate abuse and enable better monitoring of 
potential abuse. Additionally, we have concluded that the same policy 
should apply regardless of whether the discount is for the transmission 
provider's own wholesale use (i.e., wholesale merchant function), for 
the transmission provider's affiliate, or for a non-affiliate.
    A transmission provider should discount only if necessary to 
increase throughput on its system. While the potential for abuse is 
most obvious in situations involving the transmission provider's own 
wholesale use or use by an affiliate (own use/affiliate),<SUP>286 we 
must also be concerned with a transmission provider agreeing to 
discount to non-affiliates in any unduly discriminatory manner. To 
satisfy these dual concerns, we believe that any ``negotiation'' 
<SUP>287 between a transmission provider and potential transmission 
customers should take place on the OASIS. Toward this end, we believe 
three principal requirements are appropriate. (These requirements would 
remain even after negotiation takes place on the OASIS.)
---------------------------------------------------------------------------

    \286\ We clarify that own use/affiliate transactions include all 
transactions where the transmission provider or any of its 
affiliates is either the buyer, seller, marketer, or broker of 
wholesale power.
    \287\ ''Negotiation'' would only take place if the transmission 
provider or potential customer seeks prices below the ceiling prices 
set forth in the tariff.
---------------------------------------------------------------------------

    First, any offer of a discount for transmission services made by 
the transmission provider must be announced to all potential customers 
solely by posting on the OASIS. This requirement, which will ensure 
that all potential transmission customers under

[[Page 12332]]

the pro forma tariff will have equal access to discount information, 
will guard against own use/affiliate customers gaining an unfair timing 
advantage concerning the availability of discounts.
    Second, we will require that any customer-initiated requests for 
discounts occur solely by posting on the OASIS, regardless of whether 
the customer is an own use/affiliate or a non-affiliate. We have 
considered, and rejected at least for now, a more restrictive approach 
which would require that all discounts be initiated solely through 
offers by the transmission provider. Under such an arrangement, 
negotiations for discounts would effectively take place by customers 
accepting or not accepting the offered discount. While such an 
arrangement could better protect against affiliate abuse, it might be 
less efficient.<SUP>288 Accordingly, we will permit customer-initiated 
requests for discounts but will require that such requests be visible 
(via posting on the OASIS) to all market participants.
---------------------------------------------------------------------------

    \288\ For example, requiring the transmission provider to wait 
to see if an offered 5% discount clears the market would appear to 
be less efficient than permitting the customer to advise the 
transmission provider (via the OASIS) of its need for a higher 
discount in order to take service.
---------------------------------------------------------------------------

    Finally, we will require that, once the transmission provider and 
customer agree to a discounted transaction, the details (e.g., price, 
points of receipt and delivery, and length of service) be immediately 
posted on the OASIS. This requirement will be equally applicable 
regardless of whether the customer is an own use/affiliate or non-
affiliate.
    We will also revise our policy with respect to the transmission 
paths on which a discount must be offered. Many petitioners argue that 
the policy in Order No. 888, particularly that the discount rate must 
be offered over all unconstrained paths, is too broad, and may provide 
disincentives for the efficient operation of the transmission grid. 
Their concerns include, for example, the possibility that the policy 
would inhibit the transmission provider from offering discounts that 
would relieve line constraints. For example, PacifiCorp argues that it 
would be reluctant to offer a discount on northbound power flows that 
would relieve transmission constraints on transmission paths that are 
normally used for southbound flows, if by virtue of discounting 
northbound flows, it would also be required to discount all 
unconstrained southbound flows. Another concern is that while requiring 
discounts on all unconstrained paths could conceivably result in more 
service being provided, it may not have that effect. Since the level of 
transmission revenues will decline if the discount applies to all 
unconstrained paths and this, in turn, could reduce the credit to firm 
transmission users for non-firm service revenues, transmission 
providers may simply decide not to discount a particular unconstrained 
path. In light of these persuasive arguments, we will no longer require 
the transmission provider to provide the same discount over all 
unconstrained paths.
    Under our revised policy, if the transmission provider offers a 
discount on a particular path, i.e., from a point of receipt to a point 
of delivery, the transmission provider must offer the same discount for 
the same time period on all unconstrained paths that go to the same 
point(s) of delivery on the transmission provider's system. In this 
regard, a point of delivery includes an interconnection with another 
control area. Also, if a power purchaser can take delivery at more than 
one point of delivery (such as two substations serving a municipality), 
we would consider these to be the same point of delivery for 
discounting purposes.
    This change provides some flexibility to transmission providers to 
set prices for transmission service efficiently and at the same time 
maintains the requirement that public utilities provide comparable 
service at rates that are not unduly discriminatory or preferential. 
The change is designed to ensure that the transmission owner will 
provide the same discounted service to its competitors that it provides 
to itself or its affiliates for their wholesale sales.
    The Commission considered requiring the transmission provider 
offering a discount on a particular path to offer discounts on all 
unconstrained paths that go from the same points of receipt on the 
transmission provider's system and decided that such a requirement was 
not necessary to ensure comparability.
    We further clarify that a transmission provider may limit its 
offers of discounts over the OASIS to particular time periods. There is 
nothing per se unduly discriminatory in offering a discount in one 
period and not in another.\289\
---------------------------------------------------------------------------

    \289\ Thus, there is no need to revise contracts to reflect 
later offered discounts.
---------------------------------------------------------------------------

    Finally, we recognize that even with this revised policy utilities 
may engage in affiliate abuse by offering discounts only at times or 
along paths that are of advantage to it or its affiliates. While 
requiring the posting of discount information on the OASIS does not 
completely eliminate the possibility of affiliate abuse, these 
procedures will allow ready identification of unduly discriminatory or 
preferential transactions, and thus make easier the preparation of 
complaints that the transmission provider is engaging in a pattern of 
discounting that indicates affiliate abuse, such as offering discounts 
preferentially at times or on paths that only the transmission provider 
or its affiliate can take advantage of, without offering discounts at 
times or on paths that its competitors can take advantage of.
    We will require that all ``negotiation'' take place on the OASIS as 
soon as practicable, as explained in Order No. 889-A.
j. Other Pricing Related Issues Not Specifically Addressed in the Final 
Rule
(1) Demand Charge Credits

Rehearing Requests

    VT DPS argues that demand charge credits for curtailments or 
interruptions are needed to provide an incentive to utilities to 
provide high quality service. It points out that the Commission has 
allowed demand charge credits in the gas pipeline context (citing 
Tennessee Gas Pipeline Co., 71 FERC para. 61,399 at 62,580).<SUP>290
---------------------------------------------------------------------------

    \290\ See also Valero.
---------------------------------------------------------------------------

Commission Conclusion

    The Commission does not believe that electrical systems will be 
less reliable as a result of our initiatives on competition and open 
access in the Final Rule. As such, the Commission does not intend to 
require demand charge credits on a generic basis to encourage reliable 
transmission service. However, because the Commission has not mandated 
any particular rate design methodology under the Final Rule pro forma 
tariff, customers are free to argue in the compliance filing 
proceedings or subsequent section 205 proceedings that demand charge 
credits are reasonable in the context of a particular rate design 
method.
(2) In-Kind Transactions

Rehearing Requests

    CCEM asserts that in-kind transactions in reformed power pool 
agreements should be abolished because of the uncertainty of valuing 
non-cash transactions and the potential for cross subsidizing the 
utilities' generation sales. It contends that a cash equivalent 
transaction for all formerly in-kind transactions among transmission 
owners is needed.

[[Page 12333]]

Commission Conclusion

    To satisfy CCEM's concerns, the Commission concludes that in-kind 
transactions must be provided on a non-discriminatory basis. The 
Commission recently found that in-kind transactions (i.e., transactions 
with payment by energy returned in kind instead of by a monetary 
charge) with no unbundling requirement ``could hide and, thereby, mask 
unduly preferential terms and rates,'' which is precisely one of the 
practices that the Final Rule is intended to remedy.<SUP>291 While we 
will now require that all in-kind transactions be provided on an 
unbundled basis, we stress that we are not prohibiting in-kind 
transactions. Utilities are free to enter into contracts that contain 
in-kind compensation for the wholesale generation component, as long as 
it unbundles such transactions. Consistent with Arizona, unless the 
other party to the transaction contracts for transmission service under 
that utility's open access pro forma tariff, that utility must obtain 
the necessary transmission and ancillary services under the terms of 
its open access transmission tariff and must separately state the 
transmission and ancillary service prices that it will recover from the 
customer.
---------------------------------------------------------------------------

    \291\ Arizona Public Service Company, Order Addressing 
Functional Unbundling Issues, 78 FERC para. 61,016 (slip op. at 11) 
(1997) (Arizona).
---------------------------------------------------------------------------

2. Priority For Obtaining Service
a. Reservation Priority for Existing Firm Service Customers
    In the Final Rule, the Commission indicated that a transmission 
provider may reserve in its calculation of ATC transmission capacity 
necessary to accommodate native load growth reasonably forecasted in 
its planning horizon.<SUP>292
---------------------------------------------------------------------------

    \292\ FERC Stats. & Regs. at 31,745; mimeo at 323-24.
---------------------------------------------------------------------------

Rehearing Requests

    This issue is discussed in Section IV.C.5. (Reservation of 
Transmission Capacity for Future Use by Utility).
b. Reservation Priority for Firm Point-to-Point and Network Service
    In the Final Rule, in response to concerns that network service 
should have a reservation priority over point-to-point service because 
of pricing differences, the Commission allowed utilities the 
opportunity to eliminate the differences in pricing between network and 
point-to-point services by permitting utilities to adopt point-to-point 
reservations as the customer load.<SUP>293 The Commission explained 
that utilities are free to propose a single cost allocation method for 
the two services.
---------------------------------------------------------------------------

    \293\ FERC Stats. & Regs. at 31,746-47; mimeo at 326-29.
---------------------------------------------------------------------------

    In addition, the Commission provided that reservations for short-
term firm point-to-point service (less than one year) will be 
conditional until 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. According to the Commission, these 
conditional reservations may be displaced by competing requests for 
longer-term firm point-to-point service. The Commission explained that 
after the deadline, the reservation becomes unconditional, and the 
service would be entitled to the same priorities as any long-term 
point-to-point or network firm service.
    Moreover, the Commission explained that the Final Rule pro forma 
tariff does not propose point-to-point or network service with various 
degrees of firmness beyond the simple categories of firm and non-firm. 
It explained that when a customer requests firm transmission service, 
reservation priorities are established based first on availability, and 
in the event the system is constrained, based on duration of the 
underlying firm service request--customers may choose the ``firmness'' 
of service they want by electing to take non-firm service, or by 
reserving and paying for firm service.

Rehearing Requests

    NRECA and TDU Systems declare that provisions making reservations 
for short-term firm point-to-point service conditional will not reduce 
the incentive to cream skim, i.e., a customer has an incentive to 
submit reservations for very short terms without fear of not getting 
service because it can always increase its request to match another 
longer request. They suggest an alternative: all native load, network, 
and long-term firm (one year or more) requests would be given priority 
over short-term firm requests, which would have priority over non-firm 
requests.

Commission Conclusion

    The Final Rule has sufficiently minimized the potential for cream 
skimming. Further, we note that the alternative proposed by NRECA & TDU 
Systems has substantially been adopted in Order No. 888. Specifically, 
Order No. 888 provides: (1) public utilities the right to reserve 
existing transmission capacity needed for native load growth and 
network transmission customer load growth,<SUP>294 and (2) existing 
transmission customers the right of first refusal.<SUP>295 The only 
entities not covered above--potential long-term firm customers--must 
submit their service applications as far in advance as practicable.
---------------------------------------------------------------------------

    \294\ FERC Stats. & Regs. at 31,694; mimeo at 172.
    \295\ FERC Stats. & Regs. at 31,665 and 31,694; mimeo at 88 & 
172.
---------------------------------------------------------------------------

c. Reservation Priorities for Non-firm Service
    In the Final Rule, the Commission found that network economy 
purchases should have a reservation priority over non-firm point-to-
point and secondary point-to-point uses of the transmission 
system.<SUP>296
---------------------------------------------------------------------------

    \296\ FERC Stats. & Regs. at 31,748; mimeo at 332-33.
---------------------------------------------------------------------------

 Rehearing Requests

    North Jersey argues that non-firm service should be allocated on a 
first-come, first-served basis, and where multiple customers request 
service at the same time, available capacity should be allocated on a 
pro rata basis. It asserts that the proposed priority system based on 
duration of non-firm service would simply encourage non-firm customers 
to request service for longer durations than needed.

Commission Conclusion

    We reject North Jersey's argument that the proposed priority system 
based on duration of non-firm service would encourage non-firm 
customers to request service for longer durations than needed. North 
Jersey ignores the fact that section 14.2 of the pro forma tariff 
establishes a right for eligible customers with existing non-firm 
reservations to match any longer term reservation before being 
preempted.
    A related matter is discussed in Section IV.G.3.b below.
3. Curtailment and Interruption Provisions <SUP>297
---------------------------------------------------------------------------

    \297\ In the Final Rule pro forma tariff, the Commission 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.'' (pro forma tariff section 1.7). 
The pro forma tariff defines interruption as: ``A reduction in non-
firm service due to economic reasons pursuant to Section 14.7.'' 
(pro forma tariff section 1.15). The distinction between curtailment 
and interruption may have been blurred in Order No. 888 and this 
order attempts to clarify that distinction.
---------------------------------------------------------------------------

a. Pro-Rata Curtailment Provisions
    In the Final Rule, the Commission found that curtailment on a pro-
rata basis is appropriate for curtailing transactions that 
substantially relieve a

[[Page 12334]]

constraint.<SUP>298 The Commission explicitly allowed the transmission 
provider discretion to curtail the services, whether firm or non-firm, 
that substantially relieve the constraint.
---------------------------------------------------------------------------

    \298\ FERC Stats. & Regs. at 31,749; mimeo at   335-36.
---------------------------------------------------------------------------

    The Commission also indicated that it would consider granting 
deference to an alternative curtailment method to avoid hydro spill if 
such a regional practice is generally accepted and adhered to across 
the region.
    The Commission further found that under network and point-to-point 
service, the transmission provider may propose a rate treatment 
(penalty provision) to apply in the event a customer fails to curtail 
service as required under the Final Rule pro forma tariff and indicated 
that such proposals will be evaluated on a case-by-case basis on 
compliance.

Rehearing Requests

    PA Com asserts that pro rata curtailment fails to hold native load 
harmless to the extent practical as required by the FPA. PA Com points 
out that on January 19, 1994, PJM initiated pro-rata load shedding, in 
part to preserve economic transactions, leaving customers in 
Pennsylvania without power during a record cold spell.
    VA Com argues that pro rata curtailment may harm native load 
customers and section 206 complaints are after the fact and of little 
assistance to native load. VA Com argues that curtailment priority (in 
order of curtailment) should be: non-firm, contract firm, and then 
native load, and that utilities should have flexibility to curtail on a 
pro-rata basis within classes, subject to state curtailment policy.
    Several entities argue that provision must be made for preference 
in curtailment priorities obtained through settlement, through payment 
of good and valuable consideration, or under existing transmission 
contracts.<SUP>299 Turlock argues that customers should be able to 
obtain a variation from the pro rata scheme if they can show that they 
have made either past or future investments to improve constrained 
facilities and that the quid pro quo for their investment is improved 
curtailment priority.
---------------------------------------------------------------------------

    \299\ E.g., Santa Clara, Redding, TANC.
---------------------------------------------------------------------------

    Allegheny asks the Commission to clarify that it did not intend to 
require public utilities to shed (through pro rata curtailment) native 
transmission load customers in order to preserve some portion of 
service to through system users of the grid. According to Allegheny, 
the FPA mandates that service reliability to franchise customers must 
be maintained and through-system users are not similarly situated to 
native transmission load customers and should not be treated the same 
in an emergency because through system customers can protect 
themselves, but native transmission load customers cannot. Allegheny 
adds that failure to maintain system reliability would violate section 
211 of the FPA.
    CCEM asserts that hard and fast priority rules are needed to 
prevent inconsistent rules from developing for different utilities, 
pools, or control areas.

Commission Conclusion

    Assertions that the pro-rata curtailment provision in the tariff 
may harm native load customers are misplaced. The Commission clarified 
in the Final Rule that it was not requiring a pro-rata curtailment of 
all transactions at the time of a constraint, but rather curtailment of 
those transactions, whether firm or non-firm, that effectively relieve 
the constraint.<SUP>300 The Commission also required that such 
curtailments be made on a non-discriminatory basis, including the 
transmission provider's own wholesale use of the system. The Commission 
further explained that the pro-rata curtailment provision was intended 
to apply to situations where multiple transactions could be curtailed 
to relieve a constraint. Of course, if curtailment of multiple 
transactions is necessary, non-firm service would be curtailed prior to 
firm service. However, the Commission established that, in emergencies, 
the transmission provider had the discretion to interrupt firm service 
under the tariff to ensure the reliability of its transmission system.
---------------------------------------------------------------------------

    \300\ FERC Stats. & Regs. at 31,749; mimeo at 335.
---------------------------------------------------------------------------

    In terms of reliability, we believe that sufficient safeguards have 
been established to protect native load. In particular, the 
transmission provider is responsible for planning and maintaining 
sufficient transmission capacity to safely and reliably serve its 
native load. Order Nos. 888 and 889 permit the transmission provider to 
reserve, in its calculation of ATC, sufficient capacity to serve native 
load.
    Allegations that a utility did not curtail on a non-discriminatory 
basis, but instead favored a certain class of customer or type of 
transaction should be filed in a section 206 complaint proceeding to be 
reviewed on a case-specific basis. While it is true that such 
complaints will be processed on an after-the-fact basis, it is only on 
a fact-specific basis that such complaints can be fully and adequately 
reviewed.
    Additionally, tariff section 14.7 does in fact establish that for 
curtailment purposes, non-firm point-to-point transmission shall be 
subordinate to firm transmission service and non-firm service may also 
be interrupted for economic reasons. However, adopting curtailment 
schemes based solely on classes of service, as proposed by the VA Com, 
is inappropriate. Specifically, VA Com's proposal to curtail all non-
firm transmission transactions prior to firm transactions could 
exacerbate an emergency situation. For example, a curtailment could be 
necessary due to a constraint affecting northbound transactions. 
However, curtailing all non-firm transactions, including southbound 
transactions (or counterflows), could worsen the situation. 
Accordingly, the Commission believes the approach established in the 
Final Rule of allowing non-discriminatory curtailments of the 
transaction(s) that effectively relieve(s) the constraint is 
appropriate.
    In response to CCEM's concerns regarding the potential for 
inconsistent rules for different utilities, pools or control areas, the 
Commission explained in the Final Rule that any proposed deviations 
from the non-price terms and conditions of the pro forma tariff, such 
as regional practices, must be adequately supported by the utility 
proposing the change.
    Finally, Order No. 888 did not abrogate existing contracts; 
<SUP>301 therefore, customers with unique curtailment priorities 
established by pre-existing contracts would not have these priorities 
eliminated for the term of the existing contract.
---------------------------------------------------------------------------

    \301\ We note that in Order No. 888 we partially modified 
existing economy energy coordination agreements. FERC Stats. & Regs. 
at 31,666; mimeo at 91.
---------------------------------------------------------------------------

b. Curtailment and Interruption Provisions for Non-firm Service
    In the Final Rule, the Commission explained that it had clarified 
in the pro forma tariff that a network customer's economy purchases 
have a higher priority than non-firm point-to-point transmission 
service (citing AES Power, Inc. <SUP>302). <SUP>303
---------------------------------------------------------------------------

    \302\ 69 FERC para. 61,145 at 62,300 (1994) (proposed order), 74 
FERC para. 61,220 (1996) (final order).
    \303\ FERC Stats. & Regs. at 31,750; mimeo at 338-39.
---------------------------------------------------------------------------

    The Commission also revised the pro forma tariff to allow the 
transmission provider to curtail non-firm service for reliability 
reasons or to interrupt the service for economic reasons (i.e., in 
order to accommodate (1) a request for

[[Page 12335]]

firm transmission service, (2) a request for non-firm service of 
greater duration, (3) a request for non-firm transmission service of 
equal duration with a higher price, or (4) transmission service for 
economy purchases by network customers from non-designated resources). 
The Commission further explained that a firm point-to-point customer's 
use of transmission service at secondary points of receipt and delivery 
will continue to have the lowest priority.

Rehearing Requests

    For comparability, CCEM asserts that secondary receipt points 
should be made subordinate to other firm services, <SUP>304 but should 
have priority over non-firm point-to-point transactions. CCEM also 
argues that non-firm point-to-point service, once scheduled, should not 
be interrupted to accommodate non-firm service for a network service 
economy purchase.
---------------------------------------------------------------------------

    \304\ A firm point-to-point customer has a right to change its 
receipt points if capacity is available. These changed receipt 
points are known as secondary receipt points. The issue addressed 
here is the priority that is assigned to those secondary receipt 
points.
---------------------------------------------------------------------------

    VT DPS argues that firm flexible point-to-point service over 
secondary points of receipt and delivery should have a priority over 
non-firm point-to-point service (citing sections 14.2 and 14.7 of the 
pro forma tariff). It argues that this priority is necessary to reflect 
the fact that point-to-point customers pay for firm service and to be 
consistent with the treatment of network customers. VT DPS notes that 
in the natural gas industry the Commission has found that such priority 
is essential to reflect the fact that firm customers are paying for 
firm service (citing Order No. 636-B).
    APPA asks the Commission to clarify the conditions under which the 
Commission will allow non-firm service to be interrupted by the 
transmission provider solely for economic reasons. APPA claims that 
this clarification is needed so as to prevent interruption of service 
on a discriminatory basis.
    CCEM states that non-firm point-to-point transmission service does 
not provide the user with a specific capacity reservation, and 
therefore such service should bear no reservation or demand-like 
charges and the customer should pay a commodity-only charge only for 
when the service is being provided. <SUP>305 It contends, for example, 
that if a customer schedules one week of weekly non-firm transmission 
service and is interrupted on the second day of service, the customer 
should only pay for the service it used and should have no 
responsibility to take or to pay for service for the remainder of the 
week. Alternatively, it argues that if there are reservation charges 
and the non-firm customer pays for service on a ``take-or pay basis'' 
regardless of use, non-firm service should not be subject to being 
bumped once service is scheduled and power is flowing. Moreover, if the 
non-firm point-to-point transmission customer does pay reservation 
charges on a ``take-or-pay basis,'' the non-firm reserved capacity 
should be tradeable in a secondary market.
---------------------------------------------------------------------------

    \305\ See also Tallahassee.
---------------------------------------------------------------------------

Commission Conclusion

    We reject CCEM's proposal to prevent scheduled non-firm 
transmission service from being interrupted to accommodate economy 
purchases for network customers. Non-firm service is provided on an 
interruptible basis. To the extent CCEM wishes to obtain service that 
cannot be interrupted to accommodate other transactions, it has the 
option of requesting firm service in the form of either network or 
point-to-point transmission service.
    APPA's concerns have already been addressed by the Commission. In 
the Final Rule, the Commission specifically listed the economic reasons 
that a transmission provider could interrupt non-firm point-to-point 
transmission to include:

accommodat[ing] (1) a request for firm transmission service, (2) a 
request for non-firm service of greater duration, (3) a request for 
non-firm transmission service of equal duration with a higher price, 
or (4) transmission service for economy purchases by network 
customers from non-designated resources.<SUP>[306]

    \306\ FERC Stats. & Regs. at 31,750; mimeo at 338.
---------------------------------------------------------------------------

    CCEM's arguments are misplaced in that they focus on the specific 
rate (including any potential credits for service interruption) that 
utilities may propose for non-firm point-to-point transmission service. 
Order No. 888 did not mandate any pricing methodology to be used for 
non-firm point-to-point transmission service. Rather, the Commission 
established the minimum non-price terms and conditions necessary to 
ensure comparable service. As the Commission explained in the Final 
Rule, utilities are free to propose any rates for non-firm point-to-
point transmission in a section 205 filing consistent with the 
Commission's Transmission Pricing Policy Statement.<SUP>307 However, 
the Commission will evaluate the appropriateness of such proposed rates 
against the non-price terms and conditions established in the pro forma 
tariff or other non-price terms and conditions proposed and fully 
supported by the utility.<SUP>308
---------------------------------------------------------------------------

    \307\ FERC Stats. & Regs. at 31,769-70; mimeo at 395-99.
    \308\ We note that CCEM has pursued these arguments (raised on 
rehearing) in utility-specific rate cases and its objections will be 
addressed there.
---------------------------------------------------------------------------

    The Commission has previously addressed VT DPS' point.<SUP>309 Non-
firm point-to-point customers pay for non-firm service as their 
service. Firm point-to-point customers, on the other hand, contract and 
reserve a specified amount of service over designated points of receipt 
and delivery. The Commission permitted these firm point-to-point 
customers to use secondary non-firm service (from points of receipt/
delivery other than those designated in their service agreement) on an 
as-available basis at no additional charge. Because the firm point-to-
point customers taking secondary non-firm are accorded this scheduling 
flexibility at no additional charge, they are properly accorded a lower 
priority than stand alone, non-firm transmission. In contrast, network 
customers are responsible for paying for a percentage of total system 
transmission costs in order to serve their designated network loads 
whether the energy is from designated network resources or from non-
designated resources on an as-available basis.<SUP>310 Because the 
network customer pays a load-ratio share of total transmission costs, 
it receives a higher priority. Significantly, if any firm point-to-
point customer wants to avail itself of the higher priority associated 
with economy energy purchases under the network tariff, it is free to 
do so by undertaking the cost responsibilities associated with network 
service.
---------------------------------------------------------------------------

    \309\ See FERC Stats. & Regs. at 31,750; mimeo at 338, and AES 
Power, Inc., 69 FERC para. 61,145 at 62,300 (1994) (proposed order), 
74 FERC para. 61,220 (1996) (final order).
    \310\ This is comparable to the service a utility provides its 
native load.
---------------------------------------------------------------------------

    Finally, in response to VT DPS, we note that we have chosen 
different approaches in the electric and natural gas areas. In this 
regard, we recognize that there is a trade-off between encouraging 
tradable capacity rights versus maximizing revenues that can be 
credited against the transmission provider's costs of providing 
transmission service. On the electric side, fully developed 
transmission capacity trading rights simply do not exist at this time, 
and so we have chosen to emphasize an approach that maximizes revenues 
to be credited to transmission customers. However, we will continue to 
evaluate our approach in the context of any future transmission rate 
proposal that is based on the concept of tradable capacity rights.

[[Page 12336]]

4. Reciprocity Provision
    In the Final Rule, the Commission concluded that it was appropriate 
to require a reciprocity provision in the pro forma tariff.<SUP>311 The 
Commission explained that this provision will be applicable to all 
customers, including non-public utility entities such as municipally-
owned entities and RUS cooperatives, that own, control or operate 
interstate transmission facilities and that take service under the open 
access tariff, and any affiliates of the customer that own, control or 
operate interstate transmission facilities.
---------------------------------------------------------------------------

    \311\ FERC Stats. & Regs. at 31,760-63; mimeo at 370-378.
---------------------------------------------------------------------------

    The Commission developed a voluntary safe harbor procedure under 
which non-public utilities would be allowed to submit to the Commission 
a transmission tariff and a request for declaratory order that the 
tariff meets the Commission's comparability (non-discrimination) 
standards. The Commission explained that if it finds that a tariff 
contains terms and conditions that substantially conform or are 
superior to those in the Final Rule pro forma tariff, it will deem it 
an acceptable reciprocity tariff and require public utilities to 
provide open access service to that non-public utility.
    If a non-public utility chooses not to seek a Commission 
determination that its tariff meets the Commission's comparability 
standards, the Commission declared that a public utility could refuse 
to provide open access transmission service. However, any such denial 
must be based on a good faith assertion that the non-public utility has 
not met the Commission's reciprocity requirements.
    In support of its decision to adopt a reciprocity provision, the 
Commission explained that it was not requiring non-public utilities to 
provide transmission access, but was conditioning the use of public 
utilities' open access services on an agreement to offer open access 
services in return. The Commission noted that non-public utilities can 
choose not to take service under public utility open access tariffs and 
can instead seek voluntary service from the public utility on a 
bilateral basis.
    The Commission further explained that the reciprocity requirement 
strikes an appropriate balance by limiting its application to 
circumstances in which the non-public utility seeks to take advantage 
of open access on a public utility's system. However, the Commission 
recognized that Congress has determined that certain entities in the 
bulk power market can use tax-exempt financing by issuing bonds that do 
not constitute ``private activity bonds'' <SUP>312 or by financing 
facilities with ``local furnishing'' bonds.<SUP>313 The Commission 
stated that it was not its purpose to disturb Congress' and the IRS's 
determinations with respect to tax-exempt financing. Therefore, the 
Commission clarified that reciprocal service will not be required if 
providing such service would jeopardize the tax-exempt status of the 
transmission customer's (or its corporate affiliates') bonds used to 
finance such transmission facilities.<SUP>314
---------------------------------------------------------------------------

    \312\ See 26 U.S.C. Sec. 141. Interest on private activity bonds 
is taxable unless the bonds are qualified bonds for which a specific 
exception is included in the Internal Revenue Code.
    \313\ See 26 U.S.C. Sec. 142.
    \314\ The Commission also clarified that reciprocal service will 
not be required if providing such service would jeopardize a G&T 
cooperative's tax-exempt status.
---------------------------------------------------------------------------

    With respect to local furnishing bonds, which are available to a 
handful of public utilities, the Commission noted that Congress, in 
section 1919 of the Energy Policy Act, amended section 142(f) of the 
Internal Revenue Code to provide that a facility shall not be treated 
as failing to meet the local furnishing requirement by reason of 
transmission services ordered by the Commission under section 211 of 
the FPA if ``the portion of the cost of the facility financed with tax-
exempt bonds is not greater than the portion of the cost of the 
facility which is allocable to the local furnishing of electric 
energy.'' <SUP>315 So that any local furnishing bonds that may exist do 
not interfere with the effective operation of an open access 
transmission regime, the Commission required any public utility that is 
subject to the Open Access Rule that has financed transmission 
facilities with local furnishing bonds to include in its tariff a 
similar provision that it will not contest the issuance of an order 
under section 211 of the FPA requiring the provision of such service, 
and will, within 10 days of receiving a written request by the 
applicant, file with the Commission a written waiver of its rights to a 
request for reciprocal service from the applicant under section 213(a) 
of the FPA and to the issuance of a proposed order under section 
212(c).
---------------------------------------------------------------------------

    \315\ 26 U.S.C. Sec. 142(f)(2)(A).
---------------------------------------------------------------------------

    In addition, the Commission limited the reciprocity requirement to 
the applicant and corporate affiliates. The Commission explained that 
if a G&T cooperative seeks open access transmission service from the 
transmission provider, then only the G&T cooperative, and not its 
member distribution cooperatives, would be required to offer 
transmission service. However, if a member distribution cooperative 
itself receives transmission service from the transmission provider, 
then it (but not its G&T cooperative) must offer reciprocal 
transmission service over any interstate transmission facilities that 
it may own, control or operate.
    Furthermore, the Commission explained that a non-public utility, 
for good cause shown, may file a request for waiver of all or part of 
the reciprocity requirement.
    The Commission also explained that the reciprocity requirement will 
apply to any entity that owns, controls or operates interstate 
transmission facilities that uses a marketer or other intermediary to 
obtain access. The Commission added that it would apply the same 
criteria to waive the reciprocity condition for small non-public 
utilities as for small public utilities.

Rehearing Requests

Reciprocity Provision--Public Power Position

    A number of public power entities argue that the reciprocity 
provision should be eliminated because the Commission cannot require 
indirectly what it cannot require directly.<SUP>316 Several other 
public power entities add that the reciprocity obligation is beyond the 
jurisdiction of the Commission because the transmission obligations of 
non-public utilities (e.g., municipal utilities) are established and 
limited to those required by sections 211 and 212 of the FPA.<SUP>317 
Tallahassee asserts that the Commission's conditioning approach has the 
effect of excluding an entire class of transmission customer from open 
access, i.e., those unable to grant reciprocal service. This, 
Tallahassee asserts, is discriminatory and contrary to the purpose of 
the Final Rule and the requirements of sections 205, 206 and 212 of the 
FPA. TANC argues that the Commission does not have the discretion to 
grant or withhold open access transmission on the condition that the 
customer consent to doing something that the Commission admits it 
cannot directly order: ``The Commission has never `conditioned' its 
duty to allow only just and reasonable rates on any action by the 
customer.'' (TANC at 16).
---------------------------------------------------------------------------

    \316\ E.g., NRECA, Oglethorpe, AEC & SMEPA, TANC.
    \317\ E.g., Redding, Tallahassee, TANC, Dairyland.
---------------------------------------------------------------------------

    A number of entities challenge the Commission's assertion that the 
reciprocity requirement for non-public

[[Page 12337]]

utilities is voluntary.<SUP>318 Dairyland contends that the alternative 
of seeking a bilateral agreement is illusory--even if it could be 
obtained--because Order No. 888 provides that any bilateral wholesale 
coordination agreement executed after July 9, 1996 will be subject to 
open access requirements. Dairyland argues that the phrase ``subject to 
open access requirements'' presumably would include the reciprocity 
requirement for non-public utilities.
---------------------------------------------------------------------------

    \318\ E.g., NRECA, Dairyland, TDU Systems, AEC & SMEPA.
---------------------------------------------------------------------------

    AEC & SMEPA assert that there is no record support for the 
contention that non-public utilities are responsible for closed systems 
or that such systems, if any, have an impact on the market.
    NRECA asserts that if the reciprocity provision is retained, the 
Commission should ``modify its terms to incorporate the statutory 
standards and protections which FPA sections 211 and 212 contain.'' 
<SUP>319
---------------------------------------------------------------------------

    \319\ NRECA at 29. NRECA specifically lists the following: 
reliability of electric service; impairment of contracts; ability to 
cease service; all costs associated with the service must be 
recovered; retail marketing areas; and prohibitions on retail 
wheeling and sham wholesale transactions. See also Oglethorpe.
---------------------------------------------------------------------------

    Umatilla Coop asks the Commission to clarify that distribution 
cooperatives will not become subject to the reciprocity requirements 
merely because they purchase power from affiliated cooperatives that 
are acting as power marketers. TDU Systems assert that a cooperative 
should not have to render reciprocal service if it would interfere with 
its ability to obtain RUS loan financing.
    TAPS declares that the transmission provider alone should not have 
access to third-party systems through reciprocity. It maintains that 
the utility's long-term transmission customers should also be afforded 
access to those third-party systems so that the transmission provider 
does not have a competitive advantage. TAPS argues that a third-party 
should be required to have an open access tariff available.

Reciprocity Provision--Utility Position

    A number of utilities argue that the exemption from reciprocity for 
distribution cooperatives should be eliminated.<SUP>320 EEI and 
Montana-Dakota Utilities assert that G&Ts could eliminate their 
reciprocity obligation by selling or transferring their transmission 
facilities to their distribution owner/members. Southwestern argues 
that the exception for distribution cooperatives puts public utilities 
at a competitive disadvantage in that distribution cooperatives can use 
a public utility's system to compete with the public utility, but a 
public utility cannot use the distribution cooperatives' systems to 
compete to sell power to their customers.<SUP>321 It adds that the 
exception allows distribution cooperatives to hide behind shell G&Ts. 
For example, Southwestern argues that Golden Spread Electric 
Cooperative is a shell G&T because it owns only small amounts of 
facilities. It concludes that reciprocal access may become especially 
important if a state implements a retail access plan because section 
211 cannot be used to obtain transmission for retail access over a 
distribution cooperative's system.
---------------------------------------------------------------------------

    \320\ E.g., EEI, Entergy, Montana-Dakota Utilities, 
Southwestern, Oklahoma E&G, Southern.
    \321\ See also Oklahoma E&G.
---------------------------------------------------------------------------

    Southern claims that cooperatives have argued in courts and in 
Congress that a G&T cooperative and its distribution cooperative owners 
are unified economic interests in which the interest of the whole is 
equal to the sum of the parts, and that federal courts have upheld this 
view (citing one case--City of Morgan City v. South Louisiana Electric 
Cooperative Ass'n, 49 F.3d 1074 (5th Cir. 1995) (Morgan City)).
    EEI claims that clarification of certain aspects of reciprocity is 
needed: (1) public utilities may not be able to determine if reciprocal 
service is comparable because non-public utilities do not have to 
provide Form 1 data, and thus non-public utilities should be required 
to submit additional data; (2) non-public utilities should be required 
to functionally unbundle, charge rates to themselves and others that 
reflect the cost of using the system themselves, comply with the 
standards of conduct, and establish an OASIS; (3) non-public utility 
members of an RTG should be required to offer reciprocal service 
comparable to that provided by public utility members; and (4) a non-
public utility should be required to provide all services it is 
reasonably capable of providing. Carolina P&L adds that a customer 
should be required to provide the full panoply of transmission services 
that it is capable of providing because the customer has a right to 
take any type of service from the transmission provider even though it 
may only choose one particular service.
    Tucson Power asks the Commission to clarify how it will determine 
the comparability of a non-public utility's tariff. It asserts that 
first, under the safe harbor option, the Commission should clarify (1) 
that non-public utilities must comply with the Commission's rules of 
practice and procedure, and (2) how it will determine that the rates, 
terms and conditions of the reciprocal service are comparable to the 
service the non-public utility provides itself (Tucson Power argues 
that this could require submittal of data comparable to that contained 
in Form 1). Second, the Commission should eliminate the option that 
would require the public utility to determine whether the request by 
the non-public utility is consistent with the tariff. Finally, under 
the RTG option, the Commission should clarify that the evidentiary 
requirements for non-public utilities that are members of an RTG will 
be the same as for non-public utilities using the safe harbor 
procedure, i.e., any disputes regarding compliance should be resolved 
by the Commission, not the RTG.
    A number of utilities assert that the Commission should not limit 
the right to obtain reciprocity only to the public utility that 
provides the transmission service because power could actually flow 
over other public utilities' transmission lines. They argue that the 
Commission should ensure that open access transmission is as widely 
available as possible.<SUP>322 EEI asserts that Federal power marketing 
agencies, including BPA, should be required to provide comparable open 
access transmission.
---------------------------------------------------------------------------

    \322\ E.g., Montana-Dakota Utilities, Southern, EEI.
---------------------------------------------------------------------------

    Oklahoma G&E argues that Order No. 888 violates the Constitution's 
equal protection principles because it does not require universal open 
access. It asserts that the Commission has created an arbitrary 
distinction between classes of utilities that is unrelated to the 
Commission's objective and therefore is constitutionally invalid. 
Oklahoma G&E contends that the proper approach is to proceed under 
EPAct for all transmitting utilities on a case-by-case basis.
    Detroit Edison asks the Commission to clarify that the supplier and 
the recipient of power are direct beneficiaries and must be considered 
transmission customers for reciprocity purposes. Otherwise, Detroit 
Edison contends, parties from jurisdictional transmission transactions 
may be able to evade reciprocity.

Reciprocity Provision--Other Arguments

    CCEM argues that reciprocity should be expanded to require a 
transmission customer obtaining open access service also to provide 
open-access transmission service to all eligible customers. Otherwise, 
CCEM maintains, transmission owners will be able to penetrate into 
wholesale markets controlled by non-public utilities, but power 
marketers will not.

[[Page 12338]]

    CCEM asks the Commission to clarify that when a non-public utility 
obtains open access from a power pool, member of a power pool, or 
parties to some form of bilateral coordination agreement, its 
reciprocity obligation extends to all eligible customers, including all 
members of the pool or parties to the agreement.

Commission Conclusion

    We continue to believe that it is appropriate to condition the use 
of public utility open access tariffs on the agreement of the tariff 
user to provide reciprocal access to the transmission provider. No 
eligible customer, including a non-public utility, that takes advantage 
of non-discriminatory open access transmission tariff services should 
be allowed to deny service or otherwise discriminate against the open 
access provider. As we explained in the Final Rule,

[n]on-public utilities, whether they are selling power from their 
own generation facilities or reselling purchased power, have the 
ability to foreclose their customers' access to alternative power 
sources, and to take advantage of new markets in the traditional 
service territories of other utilities. While we do not take issue 
with the rights these non-public utilities may have under other 
laws, we will not permit them open access to jurisdictional 
transmission without offering comparable service in return. We 
believe the reciprocity requirement strikes an appropriate balance 
by limiting its application to circumstances in which the non-public 
utility seeks to take advantage of open access on a public utility's 
system.<SUP>[323]

    \323\ FERC Stats. & Regs. at 31,762; mimeo at 374.
---------------------------------------------------------------------------

    Contrary to arguments raised on rehearing, we are not requiring 
non-public utilities to provide transmission access. Instead, we are 
conditioning the use of public utility open access tariffs, by all 
customers including non-public utilities, on an agreement to offer 
comparable (not unduly discriminatory) services in return.<SUP>324 It 
would not be in the public interest to allow a non-public utility to 
take non-discriminatory transmission service from a public utility at 
the same time it refuses to provide comparable service to the public 
utility. This would restrict the operation of robust competitive 
markets and would harm the very ratepayers that Congress has charged us 
to protect. Very simply, we refuse to take a head-in-the-sand approach 
and order a remedy for undue discrimination that will permit the 
beneficiaries of the remedy to engage in unduly discriminatory actions.
---------------------------------------------------------------------------

    \324\ As discussed infra, non-public utilities may seek a waiver 
of the reciprocity condition. We therefore reject Tallahassee's 
argument that we are excluding an entire class of transmission 
customer from open access, i.e., those unable to grant reciprocal 
service. If the Commission determines that a particular customer 
truly is not able to reciprocate, the reciprocity condition can be 
waived. These situations are obviously different from situations 
involving entities that do not wish to provide reciprocal service.
---------------------------------------------------------------------------

    Moreover, non-public utilities are free to seek from a public 
utility a waiver of the open access tariff reciprocity condition. We 
note that this is a modification of our statements in Order No. 888, in 
which we said that non-public utilities could seek a voluntary offer of 
transmission service from a public utility on a bilateral basis. Since 
the time Order No. 888 issued, we have concluded that except in unusual 
circumstances, public utility services should be provided pursuant to 
the open access tariff and not pursuant to separate bilateral 
agreements.<SUP>325 This applies to all customers, including non-public 
utilities. Therefore, rather than requesting a bilateral agreement in 
order to avoid the reciprocity condition, non-public utilities instead 
may ask a utility for a waiver of the reciprocity condition in the 
utility's open access tariff. We disagree with Dairyland that this type 
of alternative approach is illusory. If the public utility chooses 
voluntarily to grant a waiver, the reciprocity condition would not 
apply.
---------------------------------------------------------------------------

    \325\ See Public Service Electric & Gas Company, 78 FERC para. 
61,119, slip op. at 4 and n.7 (1997).
---------------------------------------------------------------------------

    We reject NRECA's request that we incorporate in the reciprocity 
condition the statutory standards and protections of FPA sections 211 
and 212. NRECA states on rehearing that mandated services to third 
parties would endanger cooperatives' ability to provide service to 
members, or increase members' costs. It further states that sections 
211 and 212 provide substantive protections to ensure continued service 
to the transmitting utility's own customers, and to avoid their 
subsidization of services to third parties. NRECA appears to believe 
that these substantive protections are not provided outside the context 
of sections 211 and 212. We disagree. We believe the protections that 
NRECA is seeking are contained in the pro forma tariff and, as required 
by section 6 of the tariff, the non-public utility must offer its 
service on similar terms and conditions.<SUP>326
---------------------------------------------------------------------------

    \326\ With regard to the basic substantive protections such as 
reliability, opportunity to recover costs, and the standards for 
rates, terms and conditions of transmission service, we see no 
relative distinctions between sections 211 and 212 and sections 205 
and 206 of the FPA.
---------------------------------------------------------------------------

    We also reject requests that we not grant the exception to 
reciprocity provided in the Final Rule for distribution cooperatives 
and joint action agencies. We continue to believe that if a G&T 
cooperative seeks open access transmission service from the 
transmission provider, then only the G&T cooperative, and not its 
member distribution cooperatives, should be required to offer 
transmission service.<SUP>327 Without a corporate affiliation between 
G&T cooperatives and their member distribution cooperatives, we do not 
believe it is appropriate to apply the reciprocity condition to the 
member distribution cooperatives. To do so would result in the member 
distribution cooperatives being bound by their G&T 
cooperatives.<SUP>328
---------------------------------------------------------------------------

    \327\ In response to Southern's citation to Morgan City, while 
this case provides some background as to the relationship between 
G&T cooperatives and distribution cooperatives, it in no way 
suggests that the relationship rises to the level of a corporate 
affiliation.
    \328\ However, in response to Umatilla Coop, we clarify that to 
the extent a distribution cooperative purchases power from an 
affiliated cooperative that is acting as a power marketer, the 
distribution cooperative will be subject to the reciprocity 
condition because of the marketing affiliate relationship between 
the two. Moreover, as we explained in the Final Rule, the 
reciprocity condition also applies to any entity that owns, controls 
or operates transmission facilities and that uses a marketer or 
other intermediary to obtain access. FERC Stats. & Regs. at 31,763; 
mimeo at 378.
---------------------------------------------------------------------------

    Carolina P&L has brought to our attention a possible 
misunderstanding as to the meaning of comparable transmission service 
that a non-public utility must agree to provide as a condition of using 
an open access tariff. Because a non-public utility may choose any type 
of service from a public utility transmission provider that the 
transmission provider provides or is capable of providing, we clarify 
that a non-public utility seeking to take service under the 
transmission provider's open access tariff must likewise agree to offer 
to provide the transmission provider any service that the non-public 
utility provides or is capable of providing on its system in order to 
satisfy reciprocity. We note that in the Final Rule we explained that 
``[a]ny public utility that offers non-discriminatory open access 
transmission for the benefit of customers should be able to obtain the 
same non-discriminatory access in return.'' <SUP>329 In this regard, 
because a public utility must have an OASIS and a standard of conduct 
for employee separation, so must a non-public utility that seeks open 
access transmission from a public utility.<SUP>330
---------------------------------------------------------------------------

    \329\ FERC Stats. & Regs. at 31,760; mimeo at 370.
    \330\ See South Carolina Public Service Authority (Santee 
Cooper), 75 FERC para. 61,209 (1996); Central Electric Cooperative, 
Inc., 77 FERC para. 61,076 (1996). Of course, the non-public utility 
can always seek a waiver of the OASIS and standard of conduct 
requirements. Such a waiver request will be evaluated under the same 
criteria applicable to a waiver requests by a public utility.

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

[[Page 12339]]

    At the same time, however, we deny requests to expand the 
reciprocity condition.<SUP>331 Although we believe that non-public 
utilities should provide open access transmission as a matter of 
policy, to require non-public utilities to offer transmission service 
to entities other than the public utility transmission providers 
increases the chances that they could lose tax-exempt status. 
Accordingly, we have adopted a policy that recognizes the statutory tax 
restrictions placed on non-public utilities but also balances the 
fundamental unfairness of requiring a utility to make its facilities 
available to someone who could use that access to the competitive 
disadvantage of the utility. Ultimately the public interest is best 
served by nationwide open access and, if the tax issue is favorably 
resolved, we may revisit the matter.
---------------------------------------------------------------------------

    \331\ In reaching this conclusion, we note that the electric 
industry currently conducts business using contract path pricing. If 
we are presented with a regional proposal for flow-based pricing, we 
will reconsider whether there is a need to expand reciprocity as 
requested by certain entities.
---------------------------------------------------------------------------

    Moreover, in response to Detroit Edison, we take this opportunity 
to clarify that reciprocity would apply to a wholesale purchaser if a 
generation seller obtains transmission service from a public utility to 
sell to such purchaser and such purchaser owns, operates or controls 
interstate transmission facilities. The same would be true where the 
seller owns, operates and controls interstate transmission facilities 
and the buyer arranges for the transmission service. Just as with 
marketers or other intermediaries, we do not intend to allow 
reciprocity to be defeated simply on the basis of whether the seller or 
buyer requests transmission. Such a result would elevate form over 
substance.
    With respect to TDU System's assertion that reciprocal service 
should not have to be rendered if it would interfere with RUS loan 
financing, we note that we have already indicated that reciprocal 
service need not be provided if tax-exempt status would be jeopardized. 
If TDU Systems is arguing that we should not require reciprocal service 
if RUS attaches such a condition in its regulation of RUS-financed 
cooperatives, we reject such an argument. Such cooperatives have the 
option to seek bilateral service agreements.
    We reject EEI's and Tucson Power's argument that non-public 
utilities must provide Form 1 data in order to provide comparable 
service. The Form 1 data would be relevant only if the Commission were 
setting non-public utilities' rates. Such a detailed review is not 
necessary, however. See Santee Cooper, 75 FERC para. 61,209 (1996). 
Similarly, there is no need to have non-public utilities follow our 
Rules of Practice and Procedure to satisfy reciprocity.

Rehearing Requests

Safe Harbor/Waiver Provisions

    NRECA states that the following issues related to safe harbor 
status and declaratory order requests need clarification: (1) under 
what statutory authority is the Commission considering such petitions? 
(2) what rights do non-public utilities have to obtain review of 
Commission determinations with which they disagree? (3) how closely 
will a reciprocal tariff have to conform to Order No. 888 to win 
approval? (4) will non-public utilities have to pay the standard fee 
(now $11,550) with a declaratory order petition? <SUP>332 and (5) will 
the Commission allow non-public utilities to include a stranded cost 
recovery provision similar to section 26 of the pro forma tariff? 
<SUP>333
---------------------------------------------------------------------------

    \332\ NRECA raises comparable questions with respect to waiver 
procedures.
    \333\ See also TANC.
---------------------------------------------------------------------------

    Oglethorpe asserts that the Commission should not use these 
procedures to assert jurisdiction over non-public transmitting 
utilities. Dairyland contends that requiring non-public utilities to 
invoke declaratory order or waiver proceedings just to assert the clear 
statutory protections contained in sections 211 and 212 is unwarranted.
    TANC declares that the safe harbor provisions do not cure the 
problems created by reciprocity. It argues that the safe harbor 
provision expands the transmission access that must otherwise be 
offered by non-public utilities, i.e., rather than just providing 
reciprocal service to the transmission provider, under the safe harbor 
provision, the non-jurisdictional entity must offer open access to any 
eligible customers.
    Blue Ridge alleges that the safe harbor and waiver provisions face 
practical administrative problems. It asserts that a waiver itself will 
result in disputes and that the application of the waiver principle to 
non-public utilities is based on questionable statutory authority. It 
requests that the Commission add the following language to section 6 of 
the tariff: ``If the Transmission Customer is a non-public utility, the 
Transmission Provider must demonstrate a need for transmission service 
from such entity.'' (Blue Ridge at 39).
    TAPS asks that the Commission accord the filing of a waiver 
application by a small non-public utility system, or inclusion in an 
application of a sworn statement of inapplicability, the same 
protections afforded larger non-public utility systems that file under 
the safe harbor mechanism.
    Arkansas Cities ask the Commission to clarify that ``utilities like 
Arkansas Cities' members, which do not operate a control area, do not 
own `transmission' facilities and primarily purchase energy for resale 
at retail are not subject to the transmission reciprocity condition 
contained in Order 888, and are also not required to file a request for 
a waiver from the requirements of Order 888 and 889.'' (Arkansas Cities 
at 18-19)
    SWRTA and NWRTA ask the Commission to clarify that RTGs have the 
authority to issue limited waivers of the reciprocity requirements of 
Order Nos. 888 and 889 to qualifying non-public utility members of 
RTGs, and that the Commission will accord deference to an RTG's 
determination with respect to a non-public utility member's request for 
waiver of, or exemption from, these requirements.<SUP>334 They note 
that SWRTA's bylaws have a Commission-approved waiver process and 
disputes would go to arbitration or to the Commission.
---------------------------------------------------------------------------

    \334\ WRTA supports NWRTA in NWRTA's rehearing request.
---------------------------------------------------------------------------

    Southern and EEI argue that public utilities should have a parallel 
``safe harbor''--the right to seek a declaratory order as to whether 
the transmission service being offered by a non-public utility 
satisfies its reciprocity obligation.
    Tallahassee asks that the Commission clarify the good faith 
assertion a public utility must make that the non-public utility has 
not met the reciprocity requirements. It asserts that the section 211 
good faith request rules form an appropriate standard by which to 
measure a good faith assertion.

Commission Conclusion

    Several entities raise procedural and jurisdictional concerns with 
respect to our safe harbor and waiver provisions. At the outset, we 
emphasize that this Commission does not have jurisdiction over non-
public utilities under sections 205 and 206 and that the safe harbor 
mechanism and waiver provisions do not, and indeed cannot, give us such 
jurisdiction. Rather the safe harbor and waiver procedures are 
voluntary means for non-public utilities to obtain a Commission 
determination that they meet the reciprocity condition in the open 
access tariffs and thereby avoid

[[Page 12340]]

potential delays or denials of open access service based on allegations 
that the transmission requestor does not meet reciprocity. In Santee 
Cooper, issued subsequent to the Final Rule, the Commission recognized 
that it lacks jurisdiction under sections 205 and 206 over transmission 
rates, terms and conditions offered by non-public utilities, but 
explained that it has the authority to evaluate non-jurisdictional 
activities to the extent they affect the Commission's jurisdictional 
responsibilities.
    We clarify that non-public utilities that disagree with a 
Commission determination are free to request rehearing of a Commission 
order, as occurred in Santee Cooper. If aggrieved by the Commission's 
final order, they may appeal under section 313 of the FPA. Also, with 
respect to the filing fee a non-public utility entity would have to pay 
in making a declaratory order request, the Commission in Santee Cooper 
explained that its regulations specifically exempt states, 
municipalities and anyone who is engaged in the official business of 
the Federal Government from filing fees.<SUP>335 Because of the nature 
of the safe harbor and waiver provisions, we will also waive the filing 
fee for declaratory orders for all other non-public utilities in these 
circumstances.
---------------------------------------------------------------------------

    \335\ 75 FERC at 61,694-95 (citing 18 CFR 381.108).
---------------------------------------------------------------------------

    As to the question of how closely a reciprocal tariff will have to 
conform to Order No. 888, the Commission determined in Santee Cooper 
that:

    As part of its compliance filing * * * the Authority must submit 
a single tariff that conforms to the Open Access Rule pro forma 
tariff.<SUP>[336]

    \336\ 75 FERC at 61,701.
---------------------------------------------------------------------------

The Commission further explained that ``[t]he Open Access Rule requires 
that reciprocity tariffs contain terms and conditions which 
substantially conform or are superior to those in the Open Access Rule 
pro forma tariff.'' <SUP>337 We clarify, however, that in that case the 
utility chose to offer an open access tariff, whereas Order No. 888 
provides, as a condition of service, that reciprocal access be offered 
to only those transmission providers from whom the non-public utility 
obtains open access service. Therefore, a non-public utility may so 
limit the use of any voluntarily offered tariff, as long as the tariff 
otherwise substantially conforms to the pro forma tariff. We also note 
that non-public utilities are free to enter into bilateral agreements 
to satisfy the reciprocity condition. With respect to such bilateral 
reciprocal agreements, we must leave these agreements to case-by-case 
determinations. Which terms and conditions may be necessary for a non-
public utility to provide reciprocal service to the public utility in a 
bilateral agreement is necessarily a fact-specific matter not 
susceptible to resolution in a generic rulemaking proceeding. 
Additionally, we clarify that non-public utilities may include stranded 
cost recovery provisions in any reciprocity tariffs that they may 
file.<SUP>338
---------------------------------------------------------------------------

    \337\ Id.
    \338\ Because we have not extended the reciprocity condition to 
rate aspects of a non-public utility's tariff, we would not evaluate 
any stranded cost recovery mechanism and, as with respect to all 
terms and conditions of non-jurisdictional tariffs, the Commission 
is without jurisdiction to enforce such a charge.
---------------------------------------------------------------------------

    In response to TANC's concern that the safe harbor provision 
expands the transmission access that must otherwise be offered by non-
public utility entities, and Blue Ridge's concern that the safe harbor 
and waiver provisions raise practical administrative problems, we 
emphasize that both of these procedures are purely voluntary and a non-
public utility can avoid any perceived problems simply by not taking 
part in either process. We note that several entities have voluntarily 
availed themselves of these procedures without any apparent 
hardships.<SUP>339
---------------------------------------------------------------------------

    \339\ E.g., Santee Cooper, Omaha Public Power District (filed 
petition for declaratory order on October 17, 1996, which was 
docketed as NJ97-2-000), Southern Illinois Power Cooperative (filed 
petition for declaratory order on October 8, 1996, which was 
docketed as NJ97-1-000).
---------------------------------------------------------------------------

    Arkansas Cities' various waiver requests are best addressed on a 
case-by-case basis that permits a full airing of the factual 
circumstances surrounding each entity seeking a waiver. As we explained 
in a recent order, ``the Commission will not address waiver requests in 
a generic rulemaking proceeding, but will require entities seeking 
waiver of all or part of Order Nos. 888 and 889 to submit separate, 
fact-specific requests. * * *'' <SUP>340
---------------------------------------------------------------------------

    \340\ 76 FERC para. 61,009 at 61,027 (1996).
---------------------------------------------------------------------------

    EEI's and Southern's request that public utilities be provided a 
parallel ``safe harbor'' (i.e., the right to seek a declaratory order 
as to whether the transmission service being offered by a non-public 
utility satisfies its reciprocity obligation) is denied. In the Final 
Rule, we explained that a public utility may refuse to provide open 
access transmission service to a non-public utility if its denial is 
based on a good faith assertion that the non-public utility has not met 
the Commission's reciprocity requirements. <SUP>341 Moreover, a public 
utility can file a petition to terminate transmission service if a non-
public utility is violating the reciprocity condition of its open 
access service agreement with the public utility.<SUP>342
---------------------------------------------------------------------------

    \341\ FERC Stats. & Regs. at 31,761; mimeo at 372.
    \342\ For the same reason, we deny Tallahassee's request that we 
clarify the good faith assertion a public utility must make that the 
non-public utility has not met the reciprocity condition.
---------------------------------------------------------------------------

    In response to SWRTA and NWRTA's request to clarify that RTGs have 
the authority to issue limited waivers of the reciprocity conditions of 
the Order No. 888 pro forma tariffs, we recognize that RTGs have 
procedures in place to resolve disputes that may arise concerning a 
non-public utility member's request for service from a public utility 
member. Because RTGs have these dispute resolution procedures in place, 
we clarify that RTGs, which are in themselves reciprocal voluntary 
arrangements, may determine whether to apply reciprocity between and 
among member public utilities and member non-public utilities, subject 
to the RTG dispute resolution procedures authorized by this Commission.

Rehearing Requests

Retail Wheeling

    Dairyland contends that the Commission improperly requires a non-
public utility to provide retail wheeling if it uses the open access 
tariff of a public utility that allows retail access either voluntarily 
or as part of a state-mandated program.

Commission Conclusion

    Contrary to Dairyland's contention, nothing in the Final Rule 
requires a non-public utility to provide retail wheeling. Section 
212(h) of the FPA explicitly prohibits the Commission from ordering 
retail transmission directly to an ultimate consumer. If a non-public 
utility offers reciprocal service, its tariff would have to include the 
same explicit provision contained in the pro forma tariff, which states 
that an eligible customer cannot obtain transmission that would violate 
section 212(h) of the FPA, unless pursuant to a state program that 
requires the transmission provider to offer such wheeling.

Rehearing Requests

OASIS

    Southern argues that the Commission should explicitly require that 
non-public utilities must comply with Order No. 889 as part of the 
reciprocity obligation.

Commission Conclusion

    We agree with Southern and, as discussed above, absent a waiver, 
will

[[Page 12341]]

require non-public utilities to comply with Order No. 889 as part of 
the reciprocity obligation.

Rehearing Requests

Foreign Entities

    In the Open Access Rule, we decided that a foreign entity that 
otherwise meets the eligibility criteria should be able to obtain 
service under a United States public utility's open access tariff. 
However, like United States non-public utilities (which also are not 
under our section 205-206 jurisdiction), a foreign entity that owns or 
controls transmission facilities and that takes transmission service 
under a United States public utility's open access tariff must comply 
with the reciprocity provision in the tariff.<SUP>343 The reciprocity 
provision ensures that when a public utility provides service under its 
open access tariff to a transmission-owning entity that is not subject 
to the open access requirement, the public utility will be able to 
receive service in turn from that entity. In our discussion of the 
reciprocity provision, we pointed out that if a non-jurisdictional 
entity that owns or controls transmission does not wish to provide 
service to the public utility, it can choose not to use the public 
utility's open access tariff and can instead seek voluntary service 
from the public utility on a contractual basis.<SUP>344
---------------------------------------------------------------------------

    \343\ FERC Stats. & Regs. at 31,689; mimeo at 156.
    \344\ FERC Stats. & Regs. at 31,761; mimeo at 373.
---------------------------------------------------------------------------

    On rehearing, Ontario Hydro argues that the Commission has 
``unilateral[ly] impos[ed]'' the reciprocity requirement on foreign 
entities in violation of the North American Free Trade Agreement 
(NAFTA).<SUP>345 It declares that

    \345\ 32-3 Int'l Legal Materials 682 (1993); 19 U.S.C.A. 
Sec. 3301 et seq. (1995 Supp.)(legislation implementing NAFTA).
---------------------------------------------------------------------------

[u]nder the principle of national treatment, the citizens of each 
party to NAFTA * * * are allowed the same market access within 
another treaty party's market as is provided to the citizens of such 
other party. A party to these agreements cannot withhold access to 
its market by conditioning it upon receipt of equal access into the 
market of another party, because the result would be market access 
less favorable for the other party * * * than that accorded the 
party's own citizens. <SUP>346
---------------------------------------------------------------------------

    \346\ Ontario Hydro at 4-7.
---------------------------------------------------------------------------

    Ontario Hydro claims that the Open Access Rule ``makes open access 
the law of the land for wholesale transmission service within the 
United States * * *'' and that Canadian entities are thus entitled to 
such access on an unconditional basis.<SUP>347 Next, it accuses the 
Commission of trying to ``coerce'' Canada to ``conform its market 
access policy'' to United States policy and of ``impos[ing] U.S. 
regulatory policies'' on Canadian markets.<SUP>348 Finally, Ontario 
Hydro argues that even aside from the NAFTA issue, under the FPA the 
Commission does not have jurisdiction over foreign entities and thus 
cannot require reciprocity.
---------------------------------------------------------------------------

    \347\ Ontario Hydro at 5.
    \348\ Ontario Hydro at 5, 3.
---------------------------------------------------------------------------

Commission Conclusion

    We disagree with Ontario Hydro's claim that NAFTA's national 
treatment principle requires us to allow a Canadian transmission-owning 
entity (or its corporate affiliate) to take advantage of a United 
States public utility's open access tariff--a tariff we have required 
the utility to adopt--while simultaneously refusing to allow the United 
States utility to use the Canadian entity's transmission facilities. 
NAFTA's national treatment principle requires that each signatory 
``accord national treatment to the goods'' of other signatories in 
accordance with Article III of the General Agreement on Tariffs and 
Trade (GATT).<SUP>349 National treatment means that the United States 
``must not discriminate between foreign and domestic energy on the 
basis of nationality * * *'' and that Canadian electricity must be 
treated ``no less favorabl[y] than U.S. electricity, under all U.S. 
laws and rules respecting the sale, * * * distribution, and use of * * 
* electricity.'' Thus, this Commission must accord Canadian energy 
supplies treatment that is no less favorable than the treatment 
accorded United States supplies.<SUP>350 Ontario Hydro's 
interpretation, however, would twist this principle into a requirement 
that Canadian entities be treated better than United States entities, 
including United States non-public utilities that are subject to the 
reciprocity condition.<SUP>351
---------------------------------------------------------------------------

    \349\ NAFTA Article 301, citing GATT, 61 Stat. A5, A18-A19 
(1947). ``Goods'' under NAFTA include transmission service. NAFTA, 
Articles 606, 609.
    \350\ Iroquois Gas Transmission System, L.P., et al., 53 FERC 
para.61,194 at 61,700-01 (1990), aff'd sub nom. Louisiana 
Association of Independent Power Producers and Royalty Owners v. 
FERC, 958 F.2d 1101 (D.C. Cir. 1992), quoting United States-Canada 
Free Trade Agreement Implementation Act of 1988, Report of the 
Committee on Energy and Commerce, House of Representatives, H.R. 
Rep. No. 100-816, Part 7, 100th Cong., 2d Sess. at p. 7 (1988). The 
Free Trade Agreement is a predecessor to NAFTA.
    \351\ We have no section 205-206 jurisdiction over non-public 
United States utilities, just as we have no jurisdiction over 
foreign entities. Ontario Hydro's claim that the Open Access Rule 
``makes open access the law of the land for wholesale transmission 
service within the United States'' is wrong; open access is not the 
law of the land for United States non-public utilities, since we 
have no section 205-206 jurisdiction over them.
---------------------------------------------------------------------------

    Under Order No. 888, all public utility open access tariffs contain 
a reciprocity condition that applies to all users of the tariff within 
the United States, including United States non-public utilities, unless 
the condition is waived either by the Commission or the public utility 
provider. Under the reciprocity condition, non-public utilities do not 
have to offer an open access tariff (i.e., a tariff that offers 
transmission service to any eligible customer), but rather must offer 
comparable transmission services only to those transmission providers 
whose open access tariffs the non-public utility uses.<SUP>352 The same 
condition applies to foreign utilities. Thus, Ontario Hydro is in plain 
error in arguing that application of the reciprocity condition to 
foreign entities would result in less favorable treatment than that 
accorded to United States citizens. Ontario Hydro's reading of NAFTA 
would place transmission-owning Canadian entities (or their corporate 
affiliates) in a better position than any domestic entity; not only 
would Canadian entities not be subject to the open access requirement, 
but, unlike domestic non-public utilities, they would be able to use 
the open access tariffs we have mandated without providing any 
reciprocal service. Ontario Hydro has cited no precedent demonstrating 
that NAFTA imposes such an unreasonable requirement.<SUP>353
---------------------------------------------------------------------------

    \352\ United States public utilities, of course, are separately 
required by Order No. 888 to have on file open access tariffs and 
thus meet reciprocity through the separate, more stringent open 
access requirement.
    \353\ Ontario Hydro also complains that the reciprocity 
obligation of domestic non-public utilities is subject to various 
limitations and waiver provisions. These provisions apply to foreign 
entities as well.
---------------------------------------------------------------------------

    Moreover, we are not ``coercing'' Canada into adopting our policies 
or ``imposing'' open access on Canadian entities; we are simply placing 
the same condition on a Canadian entity's use of a United States 
utility's open access tariff as on a domestic non-public utility's use 
of that tariff. However, consistent with the approach we have taken in 
other contexts involving foreign utilities seeking to transact in 
United States electricity markets, we are amenable to a variety of 
approaches for Canadian utilities to meet the reciprocity 
condition.<SUP>354
---------------------------------------------------------------------------

    \354\ In recent cases involving the mitigation of transmission 
market power of Canadian utilities that are affiliates of power 
marketers that seek to sell power at market-based rates in the 
United States, the Commission has explicitly acknowledged the 
sovereign authority of Canadian governments over Canadian entities 
and has said that we will be ``amenable to a variety of approaches'' 
for foreign utilities to mitigate transmission market power. British 
Columbia Power Exchange Corporation, 78 FERC para.61,024 (1997); 
accord, TransAlta Enterprises Corporation, 75 FERC para.61,268 
(1996) and Energy Alliance Partnership, 73 FERC para.61,019 (1995).

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

[[Page 12342]]

    Ontario Hydro is also wrong in its claim that even aside from 
NAFTA, we lack authority under the FPA to require reciprocity when a 
foreign entity wishes to use a domestic utility's open access tariff. 
Just as we are not asserting jurisdiction over domestic non-public 
utilities under sections 205 or 206 of the FPA, we also are not 
asserting jurisdiction over foreign entities. Rather, we are simply 
placing the same reasonable and fair condition on both types of 
entities' uses of the transmission ordered in the Final Rule.<SUP>355
---------------------------------------------------------------------------

    \355\ EEI and Ontario Hydro note that section 6 of the tariff 
limits the obligation of foreign utilities to provide reciprocal 
service to ``facilities used for transmission of electric energy in 
interstate commerce owned, controlled or operated by the 
Transmission Customer. . . .'' (EEI at 14). This is inconsistent 
with the preamble, which says that the reciprocity provision applies 
to foreign entities (whose transmission facilities may not be 
``interstate''). We recognize that the language in section 6 of the 
pro forma tariff conflicts with the preamble language of the Final 
Rule. We are modifying section 6 of the tariff accordingly.
---------------------------------------------------------------------------

Rehearing Requests

Unconstitutional as Applied to NE Public Power District

    NE Public Power District asserts that the reciprocity provision as 
applied to NE Public Power District (a public corporation and political 
and governmental subdivision under Nebraska law) is unconstitutional. 
It argues that reciprocity would intrude into the sovereignty of 
Nebraska and would negate the decision of Nebraska's citizens to use 
their own governmental institutions to provide electric service. 
Moreover, contrary to the Commission's assertion, NE Public Power 
District states that it does not have a real choice in deciding whether 
to use the transmission service of public utilities. Because it is 
beyond the power of Congress to compel Nebraska to adopt a federally 
prescribed program for providing its citizens with electric utility 
services, NE Public Power District argues that it must follow that a 
federal agency lacks the constitutional and statutory authority to 
compel a Nebraska state instrumentality to adopt a FERC-drafted tariff 
and to modify its contracts.
    NE Public Power District states that section 201(f) of the FPA 
exempts state-owned utilities from the jurisdiction of the Commission 
and that sections 211-213 are the exclusive means by which the 
Commission can require non-public utilities to perform involuntary 
transmission service. It asserts that the Commission should exempt 
publicly-owned utilities from application of the Final Rule and notes 
that virtually all non-public utility entities are, or soon will be, 
voluntary participants in power pools, RTGs, or other similar 
organizations. Thus, NE Public Power District argues that there is no 
compelling public interest to require these entities now to submit to 
the reciprocity provision.
    In addition, NE Public Power District argues that compliance would 
conflict with Nebraska law and bond covenants, i.e., Nebraska law, for 
example, does not permit a public entity to agree in advance of a 
dispute to submit to binding arbitration. NE Public Power District 
states that it is bound by a bond covenant that prohibits it from 
rendering service free of charge and requires that a customer's default 
must be cured within a specific time. It also argues that these 
requirements are in conflict with section 7.3 of the pro forma tariff.

Commission Conclusion

    Under the Supremacy Clause of the Constitution, Nebraska law cannot 
and does not override this Commission's authorities and 
responsibilities under the FPA. Rather, this Commission has exclusive 
jurisdiction over the rates, terms and conditions of transmission in 
interstate commerce by public utilities, including reciprocity 
conditions contained in the tariffs of public utilities. Nothing in 
Order No. 888 compels Nebraska to adopt a ``federally prescribed 
program.'' While we do not have full jurisdiction over non-public 
utilities,\356\ our actions in regulating jurisdictional matters may 
impact those who wish to use jurisdictional services or to enter into 
agreements with public utilities. The Commission's obligation is to 
ensure that public utilities' services are just and reasonable and not 
unduly discriminatory or preferential and non-public utilities can 
choose to comply or not regarding matters within our exclusive 
jurisdiction. Moreover, as we explained above, NE Public Power District 
can seek waiver of the reciprocity condition on a case-by-case basis.
---------------------------------------------------------------------------

    \356\ We do have jurisdiction over many non-public utilities 
under certain sections of the FPA, e.g., sections 210, 211 and 212.
---------------------------------------------------------------------------

Rehearing Requests

QF Position

    American Forest & Paper asks the Commission to clarify that QFs are 
exempted from the reciprocity requirement or, in the alternative, grant 
them a blanket waiver. It states that QFs are not allowed to provide 
transmission service for third parties. Moreover, it asserts that there 
are unlikely to be many requests for transmission service over a QF's 
interconnection line and such cases should be handled on a case-by-case 
basis.

Commission Conclusion

    We will not grant QFs an exemption from the reciprocity condition 
or grant them a blanket waiver, but will address this issue on a case-
by-case basis if and when it arises. Because most QFs own little 
transmission, it is not likely that they will be asked to provide 
reciprocal service.
    Furthermore, in a proceeding involving a QF, we explained that use 
of a QF's transmission line by a non-QF would not affect its QF status:

    It would not fail the ownership test for QF status because, 
consistent with the requirements of the Public Utility Regulatory 
Policies Act of 1978 (PURPA), the Oxbow Geothermal facility would 
continue to be ``owned by a person not primarily engaged in the 
generation or sale of electric power (other than electric power 
solely from cogeneration facilities or small power production 
facilities).'' 16 U.S.C. Sec. 796(18)(B)(1994).<SUP>[357]

    \357\ Oxbow Power Marketing, 76 FERC para. 61,031 at 61,179 
(1996), reh'g pending. We did note, however, that the QF would 
become a public utility to the limited extent it provides 
transmission service over its line on behalf of others.
---------------------------------------------------------------------------

If a QF that owns, controls or operates interstate transmission 
facilities seeks open access transmission from a public utility, it 
must agree to provide reciprocal service to that public utility. Of 
course, the QF could file a waiver request in a separate proceeding, as 
set forth in the Final Rule and clarified in a subsequent order.\358\
---------------------------------------------------------------------------

    \358\ See Order Clarifying Order Nos. 888 and 889 Compliance 
Matters, 76 FERC para. 61,009 at 61,027 (1996).
---------------------------------------------------------------------------

Rehearing Requests

Tax-Exempt Financing Issues

Reciprocity and Private Activity Bonds
    EEI asks the Commission to require non-public utilities claiming 
that their tax status is a bar to granting reciprocity to substantiate 
such claim in a safe harbor proceeding and to take reasonable measures 
to request the IRS to allow them to provide reciprocal service while 
retaining their tax status. If the Commission decides not to require a 
safe harbor proceeding, EEI requests that the Commission require non-
public utilities to substantiate their tax concerns and to demonstrate 
to each public utility from which they seek service that they are 
actively pursuing

[[Page 12343]]

the issue with the IRS.\359\ It also urges that the Commission require 
any request for exemption from the reciprocity requirement that is 
based on jeopardy to tax-exempt status be filed with the Commission as 
part of a request for declaratory order in a safe harbor proceeding. 
Moreover, it requests that the Commission require a non-public utility 
to specifically identify the facilities it cannot use without 
jeopardizing its tax-exempt financing and to provide copies of, and 
specifically reference the tax provisions in, the related financing 
agreements that embody this restriction.
---------------------------------------------------------------------------

    \359\ See also Tucson Power.
---------------------------------------------------------------------------

    Centerior asks that the Commission condition receipt of open access 
transmission service by municipal utilities upon the elimination or 
mitigation of tax subsidies and regulatory inequities. Southern 
maintains that tax-exempt status can remain undisturbed if non-public 
utilities do not seek open access transmission service from public 
utilities. Thus, Southern asserts, non-public utilities can weigh the 
benefits of transmission service under the Final Rule against the 
potential threat to their tax benefits, and make the choice that serves 
their best interest. At a minimum, it argues, the Commission should 
await the determinations of the IRS before finalizing this aspect of 
the reciprocity provision, rather than confer yet another unique 
benefit on non-public utilities.\360\
---------------------------------------------------------------------------

    \360\ See also SoCal Edison. It asserts that the Commission 
should require publicly-owned utilities to provide open access on 
the same terms as other utilities after a short transitional period 
that provides an opportunity for the IRS and/or Congress to address 
the interrelationship between open access transmission and tax-
exempt financing.
---------------------------------------------------------------------------

    CAMU asks that the Commission defer reciprocity obligations until 
the IRS has clarified the status of private use limitations within the 
context of transmission access. Otherwise, CAMU asserts, innocent 
investors could suffer penalties because the Commission moved too 
quickly on this sensitive issue.

Local Furnishing Bonds

    Local Furnishing Utilities and ConEd state that section 5.1 of the 
pro forma tariff applies to ``Transmission Service,'' which is defined 
in section 1.48 to include point-to-point service, but not network 
service. They ask the Commission to clarify that the phrase 
``transmission service'' also applies to network service.
    Local Furnishing Utilities and ConEd ask that the Commission 
confirm that all costs associated with the loss of tax-exempt status, 
including defeasing, redeeming, and refinancing tax-exempt bonds, will 
be considered costs of providing transmission that must be borne by the 
customer for whom the transmission is provided. They state that 
defeasance and refinancing costs are just as attributable to the 
particular transmission service causing such defeasance or redemption 
as the costs of expanding the system are attributable to the service 
that cause the need for such expansion. They ask that the Commission 
clarify that a transmission provider may include in its tariff a 
provision permitting the recovery of such costs, even if a filing under 
section 205 of the FPA is required. ConEd asserts that if a customer 
does not want to pay costs associated with the loss of tax-exempt 
status on the bonds, the Commission should allow the transmission 
provider to decline to provide the requested service.
    Local Furnishing Utilities and ConEd also assert that section 5.2 
of the pro forma tariff should be clarified to state that issuance of a 
section 211 order by the Commission is a condition precedent to the 
provision of transmission service. Local Furnishing Utilities states 
that there is a question whether the Commission should insist on waiver 
of the issuance of a proposed order under section 212(c). According to 
Local Furnishing Utilities, the negotiations that normally would follow 
the issuance of a proposed order are likely to provide the only 
opportunity to demonstrate and review the costs associated with the 
loss of tax-exempt status.
    Local Furnishing Utilities and ConEd assert that sections 5.1 and 
5.2(i) of the pro forma tariff improperly limit the safe harbor 
protection of section 1919 of EPAct to transmission providers that 
financed ``transmission facilities'' with local furnishing bonds. 
Because of this, they assert, the safe harbor is not available to 
ConEd, all of whose local furnishing bonds have been used to finance 
its distribution system. They argue that section 5.1 should apply to 
service that would jeopardize the tax-exempt status of bonds that 
finance distribution or generation, as well as transmission, 
facilities. NE Public Power District contends that section 5.2(ii) 
should be amended ``to make it clear that interim service need not be 
begun if rendering the service would endanger the tax-exempt status of 
the provider's bonds, unless the customer agrees to bear the financial 
consequences of such loss of tax-exempt status and has the wherewithal 
to do so.'' (NE Public Power District at 22-23).
    SoCal Edison argues that local furnishing utilities should be 
required to comply with the Final Rule without any exception based upon 
their tax-exempt bonds.

Commission Conclusion

Private Activity Bonds

    As we explained in Order No. 888, it is not our purpose to disturb 
Congress's and the IRS's determinations with respect to tax-exempt 
financing. With respect to private activity bonds, we reaffirm our 
finding that reciprocal service will not be required if providing such 
service would jeopardize the tax-exempt status of the transmission 
customer's (or its corporate affiliates') bonds used to finance such 
transmission facilities. We remain hopeful that the IRS in its private 
activity bond rulemaking will, to the maximum extent possible, remove 
regulatory impediments that limit the ability of industry participants 
to provide reciprocal open access. As we indicated in Order No. 888, 
after the IRS acts, we will reexamine our policy to ensure that the 
reciprocity condition is applied broadly to achieve open access without 
jeopardizing tax-exempt financing.\361\
---------------------------------------------------------------------------

    \361\ We note that on January 10, 1997, the IRS issued final 
regulations on the definition of private-activity bonds applicable 
to tax-exempt bonds issued by state and local governments, but 
reserved section 1.141-7 dealing with output contracts to further 
consider the issues raised by regulatory changes in the electric 
power industry. 62 FR 2275 (January 16, 1997).
---------------------------------------------------------------------------

    We will reject the request of EEI and Tucson Power that the 
Commission require non-public utilities to substantiate in a safe 
harbor proceeding a claim that their tax status is a bar to granting 
reciprocity. As we stated in Order No. 888, if a non-public utility has 
sought a declaratory order on a voluntarily-filed tariff, we request 
that it identify the services, if any, that it cannot provide without 
jeopardizing the tax-exempt status of its financing. However, we cannot 
require that a non-public utility use the safe harbor mechanism, 
whether to file a reciprocal tariff with the Commission or to 
substantiate a claim as to loss of tax-exempt status. As we explain 
above, the safe harbor procedure is a voluntary means for non-public 
utilities to obtain a Commission determination that they meet the 
reciprocity condition in the open access tariffs and thereby avoid 
potential delays or denials of open access service based on allegations 
that the transmission requestor does not meet reciprocity.
    Nevertheless, just as we believe that it is appropriate to 
condition the use of public utility open access tariffs on the

[[Page 12344]]

agreement of the tariff user to provide reciprocal access to the 
transmission provider, we also believe it is appropriate to condition 
the use of public utility open access tariffs on the agreement of the 
non-public utility tariff user to substantiate any claim that providing 
reciprocal transmission service would jeopardize the tax-exempt status 
of its financing. The non-public utility can provide such 
substantiation by identifying for the customer the services that it 
cannot provide without jeopardizing its tax-exempt financing.\362\
---------------------------------------------------------------------------

    \362\ In response to EEI's request that the Commission require a 
non-public utility to provide copies of, and specifically reference 
the tax provisions in, the related financing agreements, we note 
that the level of detail needed to substantiate a non-public 
utility's claim that providing reciprocal transmission service would 
jeopardize the tax-exempt status of its financing is likely to 
depend on the facts of each case. As a result, what will constitute 
adequate substantiation is properly determined on a case-by-case 
basis. Additionally, we will reject EEI's request that the 
Commission require non-public utilities to demonstrate that they are 
actively pursuing the issue with the IRS. As we explain above, the 
IRS is currently examining these issues; we in turn will reexamine 
our policy after the IRS acts to ensure that the reciprocity 
condition is applied broadly to achieve open access without 
jeopardizing tax-exempt financing.
---------------------------------------------------------------------------

    Southern suggests that tax-exempt status can remain undisturbed if 
non-public utilities do not seek open access transmission service from 
public utilities and, therefore, that non-public utilities can weigh 
the benefits of transmission service under the Rule against the 
potential threat to their tax benefits. We believe it is important to 
remember why we required open access in the first place--as a remedy 
for undue discrimination in transmission services in interstate 
commerce. Southern would force a non-public utility to give up a 
Congressionally-mandated right as a condition to taking open access 
transmission. Clearly Southern's suggestion is misplaced and 
overbroad.\363\ For this reason, we believe that our decision not to 
require reciprocal service if providing such service would jeopardize 
the non-public utility's tax-exempt financing--pending action by the 
IRS in its private activity bond rulemaking--is appropriate for the 
time being.\364\ We reiterate that we will reexamine our policy after 
the IRS acts. As we state above, we believe that ultimately the public 
interest is best served by nationwide open access.
---------------------------------------------------------------------------

    \363\ We will reject Centerior's request that the Commission 
condition receipt of open access transmission service by non-public 
utilities upon the elimination or mitigation of tax subsidies. As we 
stated in Order No. 888, Congress has entrusted the IRS with the 
responsibility for implementing laws governing tax-exempt financing, 
and it is not this Commission's purpose to disturb Congress's and 
the IRS's determinations in that regard.
    \364\ In response to CAMU, we note that the Commission has, in 
effect, deferred--pending IRS action--a non-public utility's 
reciprocity obligation in cases in which the provision of reciprocal 
service would jeopardize the tax-exempt status of the non-public 
utility's financing.
---------------------------------------------------------------------------

Local Furnishing Bonds

    We clarify, in response to Local Furnishing Utilities and ConEd, 
that the reference to ``Transmission Service'' in section 5.1 of the 
pro forma tariff was intended to be to ``transmission service,'' and 
thereby to apply to point-to-point service as well as network service. 
We have revised section 5.1 accordingly.
    We further clarify that all costs associated with the loss of tax-
exempt status, including the costs of defeasing, redeeming, and 
refinancing tax-exempt bonds, are properly considered costs of 
providing transmission services. Therefore, a customer that takes 
service, understanding that such service will result in loss of tax-
exempt status, shall be responsible for such costs to the extent 
consistent with Commission policy, and a transmission provider may 
include in its tariff a provision permitting it to seek recovery of 
such costs. We clarify that if the transmission customer is not willing 
to pay the costs associated with the transmission provider's loss of 
tax-exempt status, the transmission provider will not be required to 
provide the requested service.\365\
---------------------------------------------------------------------------

    \365\ Of course if the transmission provider can provide part of 
the requested service without jeopardizing tax-exempt status, it 
should offer to provide such service.
---------------------------------------------------------------------------

    Local Furnishing Utilities and ConEd also ask the Commission to 
revise section 5.2 of the pro forma tariff to state that issuance of a 
section 211 order by the Commission is a condition precedent to the 
provision of transmission service. Under the tariff provision adopted 
by Order No. 888 to address situations in which the provision of 
transmission service would jeopardize the tax-exempt status of any 
local furnishing bonds used to finance a local furnishing utility's 
facilities, the customer requesting transmission service would tender 
an application under section 211 of the FPA. Within ten days of 
receiving a copy of the section 211 application, the transmission 
provider ``will waive its rights to a request for service under Section 
213(a) of the [FPA] and to the issuance of a proposed order under 
Section 212(c) of the [FPA] and shall provide the requested 
transmission service in accordance with the terms and conditions of 
this Tariff.'' \366\ We clarify that the Commission, upon receipt of 
the transmission provider's waiver of its rights to a request for 
service under section 213(a) and to the issuance of a proposed order 
under section 212(c), shall issue an order under section 211.\367\ Upon 
issuance of the order under section 211, the transmission provider 
shall be required to provide the requested transmission service in 
accordance with the terms and conditions of the tariff. Section 5.2 of 
the pro forma tariff has been revised accordingly.
---------------------------------------------------------------------------

    \366\ Pro Forma Open Access Transmission Tariff, Section 
5.2(ii).
    \367\ We will reject Local Furnishing Utilities' request that 
the Commission reconsider whether it should insist on the 
transmission provider's waiver of the issuance of a proposed order 
under section 212(c). As Order No. 888 indicates, this aspect of the 
local furnishing provision of the tariff is similar to a provision 
included in the transmission tariff of San Diego G&E, one of the 
Local Furnishing Utilities. Waiver of the issuance of a proposed 
order enables a transmission provider to expeditiously provide 
service under section 5.2 of the pro forma tariff, thereby ensuring 
that any local furnishing bonds that may exist do not interfere with 
the effective operation of an open access transmission regime. 
Although Local Furnishing Utilities now apparently support the 
issuance of a proposed order on the basis that the negotiations that 
normally would follow are likely to provide an opportunity to review 
the costs associated with the loss of tax-exempt status, we believe 
that any dispute as to costs subsequently can be resolved without 
causing any delay in the provision of the requested transmission 
service. For example, the service could be provided at the maximum 
rate allowed by the Commission, subject to refund.
---------------------------------------------------------------------------

    Local Furnishing Utilities and ConEd also contend that the language 
of sections 5.1 and 5.2(i) of the pro forma tariff improperly limits 
the safe harbor protection of section 1919 of EPAct to transmission 
providers that financed transmission facilities with local furnishing 
bonds. ConEd expresses concern that although all of its electric local 
furnishing bonds have been used to finance its distribution system, the 
test as to whether those bonds have been used for the ``local 
furnishing'' of electricity is based in part on whether ConEd has been 
a ``net importer'' of energy into its service territory. As a result, 
ConEd argues that the use of its transmission system to wheel power 
from a generating source located inside ConEd's service territory to a 
customer located outside its service territory could cause ConEd to 
violate the net importer rule and thereby lose the tax exemption for 
the bonds used to finance its distribution system. ConEd asks the 
Commission to modify sections 5.1 and 5.2 of the pro forma tariff to 
make clear that those provisions apply to transmission providers that 
have financed any ``facilities'' (i.e., distribution and generation, 
not just transmission, facilities) with local furnishing bonds.
    As we explained in Order No. 888, we believe the local furnishing 
bonds

[[Page 12345]]

provision in section 5 of the pro forma tariff is necessary and 
appropriate so that any local furnishing bonds that may exist do not 
interfere with the effective operation of an open access transmission 
regime. If the provision of transmission service pursuant to Order No. 
888 would result in the loss of tax-exempt status for local furnishing 
bonds, regardless of whether the facilities financed with those bonds 
are transmission, distribution, or generation facilities, it is our 
intent that the provisions of section 5 would apply. Thus, we clarify 
in response to ConEd and Local Furnishing Utilities that, to the extent 
the provision of transmission under an open access tariff would 
jeopardize the tax-exempt status of local furnishing bonds used to 
finance distribution or generation facilities (even if no transmission 
facilities were financed with such bonds), <SUP>368 such situation 
would fall within the reference to ``facilities that would be used in 
providing . . . transmission service'' contained in sections 5.1 and 
5.2(i). This is so because the loss of tax-exempt status in such 
circumstances would be directly attributable to the provision of 
transmission services under the Rule.
---------------------------------------------------------------------------

    \368\ ConEd suggests that this might occur if, for example, the 
provision by ConEd of transmission service were to cause it to 
violate the net importer rule and thereby lose the tax exemption for 
bonds used to finance its local distribution system. Although we 
clarify above that section 5 of the pro forma tariff would apply to 
this situation, we note that it is not clear that wheeling required 
by the Commission would be counted for purposes of determining 
whether a public utility is a ``net importer.'' In its committee 
report on the bill that became the Energy Policy Act, the House Ways 
and Means Committee stated:
    The committee believes further that, in applying the IRS ruling 
position that a local furnishing utility that is interconnected with 
other utilities (other than for emergency transfers of electricity) 
must be a net importer of electricity, the determination of whether 
the utility is a net importer should be made without regard to 
electricity generated by another party that is wheeled by the 
utility to a point outside its service area pursuant to a FERC order 
authorized under the bill.
    H.R. Rep. No. 102-474(VI), 102d Cong., 2d Sess. 25 (1992), 
reprinted in 1992 U.S.C.C.A.N. 2232, 2236.
---------------------------------------------------------------------------

    Further, we said in Order No. 888 that ``we will require any public 
utility that is subject to the Open Access Rule that has financed 
transmission facilities with local furnishing bonds to include in its 
tariff'' a provision similar to section 5 of the pro forma 
tariff.<SUP>369 We clarify that we did not intend by this statement 
that the section 5 local furnishing bonds provision would only apply to 
public utilities that have financed transmission facilities with local 
furnishing bonds, and not those that have financed generation and 
distribution facilities with such bonds. As we explain above, it is our 
intent that the provisions of section 5 apply if the provision of 
transmission service pursuant to an open access tariff would result in 
the loss of tax-exempt status for local furnishing bonds, regardless of 
whether the facilities financed with those bonds are transmission, 
distribution, or generation facilities.
---------------------------------------------------------------------------

    \369\ FERC Stats. & Regs. at 31,763; mimeo at 377.
---------------------------------------------------------------------------

Rehearing Requests

Unfunded Mandates Reform Act

    NE Public Power District <SUP>370 argues that the final regulations 
adopted in this proceeding ``constitute[] an unfunded mandate under the 
Unfunded Mandates Reform Act of 1995 * * * .'' <SUP>371 It declares 
that Order No. 888 imposes significant costs upon local governments and 
that the Commission was required under the Unfunded Mandates Reform Act 
to consider the financial impact of its rulemaking upon state and local 
governments and to prepare and issue as part of its rulemaking process 
a statement containing certain specified analyses and estimates 
concerning this matter and a description of its pre-issuance 
consultations with state and local government authorities. To support 
its argument NE Public Power District relies upon: (a) Executive Order 
No. 12875, Enhancing the Intergovernmental Partnership (Executive 
Order); <SUP>372 and (b) the Unfunded Mandates Reform Act of 1995 (the 
Act). <SUP>373
---------------------------------------------------------------------------

    \370\ NE Public Power District is a public corporation and a 
political subdivision of the State of Nebraska that generates, 
transmits and delivers electric energy to wholesale and retail 
customers throughout the state.
    \371\ NE Public Power District at 2. NE Public Power District 
asserts that the Commission failed to respond to this issue as 
raised by NE Public Power District in its comments.
    \372\ Executive Order No. 12875, 3 CFR 699-71 (1994); 58 Fed. 
Reg. 58,093-094 (1993). The Executive Order provides that, unless 
required by statute, no Executive department or agency shall 
promulgate any regulation that creates a mandate upon state, local 
or tribal governments unless it either: (a) provides the funds 
necessary to carry out the obligations; or (b) before promulgating 
the regulation, provides to the Director of the Office of Management 
and Budget: (1) a description of its consultation with the affected 
governments; (2) a statement of their concerns and copies of 
communications it has received from them; and (3) the reasons why it 
thinks the regulations should issue.
    \373\ The Unfunded Mandates Reform Act is Pub. L. No. 104-4, 109 
Stat. 48 (1995) (to be codified at 2 U.S.C. Secs. 602, 632, 653, 
658, 1501-1504, 1511-1516, 1531-1538, 1551-1556 and 1571).
---------------------------------------------------------------------------

Commission Conclusion

    We disagree with NE Public Power District. The Executive Order 
applies to every ``executive department * * * [and] agency. * * * '' 
<SUP>374 It defines ``executive agency'' as ``any authority of the 
United States that is an `agency' under 44 U.S.C. Sec. 3502(1), other 
than those considered to be independent regulatory agencies, as defined 
in 44 U.S.C. Sec. 3502 (10).'' <SUP>375 In section 3502(10), the 
Federal Energy Regulatory Commission is defined as an independent 
regulatory agency. As a result, the Executive Order does not apply to 
the Commission.
---------------------------------------------------------------------------

    \374\ 3 CFR at 670; 58 FR 58093 (1993).
    \375\ 3 CFR at 671; 58 FR at 58094 (1993) (emphasis supplied).
---------------------------------------------------------------------------

    The Act similarly applies to federal agencies, but, as with the 
Executive Order, does not apply to independent regulatory agencies. 
<SUP>376 Although the Act does not define ``independent regulatory 
agency,'' there is no indication that Congress intended to exclude the 
Commission from the definition. In fact, in all instances in which 
Congress has defined the term ``independent regulatory agency'' of 
which we are aware, the Commission has been included.
---------------------------------------------------------------------------

    \376\ 90 Stat 50 (to be codified at 2 U.S.C. Sec. 658).
---------------------------------------------------------------------------

    As noted, the Commission is defined as an independent regulatory 
agency in Title 44 U.S.C. Also, Title 42 U.S.C. Sec. 7176 provides 
that:

    For the purposes of chapter 9 of title 5, United States Code * * 
* [Executive Reorganization], the [Federal Energy Regulatory] 
Commission shall be deemed to be an independent regulatory agency. 
<SUP>[377]

    \377\ 42 U.S.C.A. Sec. 7176 (1995) (Department of Energy 
Organization Act) (P.L. 95-91, 91 Stat. 586) (1977). See also Pub. 
L. No. 104-13, the Paperwork Reduction Act of 1995 Sec. 3502(5), 109 
Stat. 165 (1995) (to be codified at 44 U.S.C. Sec. 3502(5)), which 
provides that ``the term `independent regulatory agency' means 
[among other agencies] * * * the Federal Energy Regulatory 
Commission.''
---------------------------------------------------------------------------

Accordingly, we find that the Commission is an independent regulatory 
agency as used in the Act; therefore, it is not covered by the Act.
    Moreover, even if the Act applied to the Commission, the Final Rule 
will not impose a Federal mandate on state, local or tribal 
governments.
    Section 305 of the Act defines a ``Federal mandate'' as:

any provision in [a] statute or regulation or [in] any Federal court 
ruling that imposes an enforceable duty upon State, local, or tribal 
governments[,] including a condition of Federal assistance or a duty 
arising from participation in a voluntary Federal program.<SUP>[378]
---------------------------------------------------------------------------

    \378\ 109 Stat. 70 (to be codified at 2 U.S.C. Sec. 1555) 
(emphasis supplied).

    The Open Access Final Rule imposes requirements only on certain 
public utilities <SUP>379 and, pursuant to section 201(f) of the FPA, 
state and local

[[Page 12346]]

governments, and their agencies, authorities and instrumentalities, are 
not public utilities. Additionally, although the Final Rule will allow 
public utilities' transmission tariffs to contain reciprocity 
provisions in order to ensure that public utilities offering open 
access transmission to others can obtain similar service from open 
access users, the reciprocity provision is not an enforceable duty. A 
duty is mandatory; it is an obligation to perform and is compulsory. 
<SUP>380 The reciprocity provision is merely a condition of receiving a 
benefit, i.e., open access transmission service from a public utility. 
<SUP>381 There is no requirement that NE Public Power District 
promulgate an open access tariff and apply to FERC for a declaratory 
order. Moreover, as we explained above, non-public utilities, such as 
NE Public Power District, are free to seek from a public utility a 
waiver of the open access tariff reciprocity condition.
---------------------------------------------------------------------------

    \379\ I.e., those that own, operate or control interstate 
transmission facilities and do not obtain a waiver from the 
Commission.
    \380\ Dayton Hudson Corp. v. Eldridge, 742 S.W. 2d 482, 485-86 
(1987); Kerrigan v. Errett, 256 N.W. 2d 394, 399 (1977); Huey v. 
King, 415 S.W. 2d 136, 138 (1967); Black's Law Dictionary 505 (6th 
ed. 1990).
    \381\ A state or municipal power authority, such as NE Public 
Power District, does not have to agree to reciprocity, and the 
Commission cannot force it to do so. The Commission is not requiring 
state or municipal power authorities to provide transmission access. 
If non-public utilities elect not to take advantage of open access 
services because they don't want to meet the tariff reciprocity 
provision, they can still seek voluntary, bilateral transmission 
service from public utilities.
---------------------------------------------------------------------------

    With regard to the Stranded Cost Final Rule, while it applies to 
non-public utilities as well as public utilities, it does not impose a 
duty on any entity since it merely permits public utilities and 
transmitting utilities to seek recovery of certain costs. As a result, 
since the Open Access and Stranded Cost final rules will not impose an 
enforceable duty on state, municipal or tribal power agencies such as 
NE Public Power District, the rules are not Federal mandates as defined 
in the Act.
    Because the Unfunded Mandates Reform Act of 1995 does not apply to 
the Commission and, in any event, the Open Access/Stranded Cost final 
rules do not impose Federal mandates on state, local or tribal 
governments, we reject NE Public Power District's argument that the 
Unfunded Mandates Reform Act of 1995 is applicable here.
5. Liability and Indemnification
    In the Final Rule, the Commission explained that the 
indemnification provision was broken into two parts (set forth in 
section 10.1 (Force Majeure) and section 10.2 (Indemnification) of the 
pro forma tariff).<SUP>382 The Commission explained that the first part 
is a force majeure provision which provides that neither the 
transmission provider nor the customer will be in default if a force 
majeure event occurs, but also provides that both the transmission 
provider and customer will take all reasonable steps to comply with the 
tariff despite the occurrence of a force majeure event.
---------------------------------------------------------------------------

    \382\ FERC Stats. & Regs. at 31,765-66; mimeo at 384-85.
---------------------------------------------------------------------------

    The Commission explained that the second portion of the provision 
provides for indemnification against third party claims arising from 
the performance of obligations under the tariff. The Commission limited 
the indemnification portion of the provision so that it is only the 
transmission customer who indemnifies the transmission provider from 
the claims of third parties. The Commission explained that the revised 
provision provides that the customer will not be required to indemnify 
the transmission provider in the case of negligence or intentional 
wrongdoing by the transmission provider.

Rehearing Requests

    A number of utilities argue that the Commission has expanded 
transmitter liability beyond the existing standard in the industry, 
i.e., gross negligence.<SUP>383 They assert that the Commission has 
provided no basis to subject transmission providers to liability, 
including consequential damages, due to ordinary negligence. KCPL 
points out that 21 of 25 states addressing this issue hold that a 
utility should not be liable for ordinary negligence. It declares that 
society will be worse off in litigation expenses and wasted human 
resources if utilities are held liable for simple negligence. It adds 
that the electric industry is much more susceptible to liability from 
interruptions of service than gas pipelines (refuting the Commission's 
reliance on Pacific Interstate Offshore Company, which it states is 
traceable to United Gas Pipeline Co. v. FERC, 824 F.2d 417 (5th Cir. 
1987)). Florida Power Corp asks the Commission to modify section 10.2 
to provide that a customer must indemnify the transmission provider 
except where a finder of fact determines that the transmission provider 
has committed gross or intentional wrongdoing. It also argues that the 
Commission should eliminate liability of both the transmission provider 
and the customer to the other for consequential damages.
---------------------------------------------------------------------------

    \383\ Coalition for Economic Competition, EEI, KCPL, Florida 
Power Corp.
---------------------------------------------------------------------------

    Southern argues that the exception language in section 10.2 should 
be changed to ``except where a court has determined that the 
Transmission Provider has engaged in intentional wrongdoing or has been 
grossly negligent.'' (Southern at 20-21). Southern also argues that the 
Commission should limit consequential damages arising from negligence 
in the operation of the transmission system.
    Puget asserts that the exception language in section 10.2 should be 
changed to ``except in cases of and to the extent of comparative or 
contributory negligence or intentional wrongdoing by the Transmission 
Provider.'' (Puget at 18). It also asserts that the Commission should 
exclude liability for special, incidental, consequential, or indirect 
damages.
    EEI argues that the Commission should add a new section 10.3: ``If 
the Transmission Provider is found liable for any damages associated 
with this Tariff, those damages shall be limited to direct damages, and 
the Transmission Provider shall not be liable for any special, indirect 
or consequential damages of any nature by virtue of the transactions 
conducted under this Tariff.'' (EEI at 26).
    Coalition for Economic Competition argues that the Commission 
should modify section 10.2 to provide that the transmission provider 
will not be liable to a transmission customer or any third party for 
damages caused by interruptions or irregular or defective service, 
except if gross negligence or wilful misconduct caused such 
damages.<SUP>384 Coalition for Economic Competition asserts that the 
definition of force majeure should include ordinary negligence and asks 
that the Commission clarify that a utility is not liable for force 
majeure events.
---------------------------------------------------------------------------

    \384\ See also EEI at 26 (suggesting ``except in cases of a 
finding by a trier of fact of gross negligence or intentional 
wrongdoing by the Transmission Provider'').
---------------------------------------------------------------------------

    CCEM also argues that transmission customer indemnity in section 
10.2 should attach only to legal actions brought by customers of the 
transmission customer or third-party beneficiaries of those customers.
    On the other hand, TDU Systems argues that the indemnity provision 
unfairly provides the transmission provider with virtually total 
indemnification for acts on its side of the delivery point, but 
provides no reciprocal protection to the transmission customers for 
damage incurred on the customers' system in connection with purchasing 
the transmission provider's services.

[[Page 12347]]

    CSW Operating Companies asks the Commission to revise the pro forma 
tariff to provide that a transmission provider will not be liable for 
errors in an estimate made in good faith and in accordance with its 
published procedure. They propose the following language:

    Information posted on the OASIS concerning the availability of 
transfer capability will be based on the Transmission Provider's 
best estimates given the information readily and actually available 
to the transmission provider. No such estimate will be binding on 
the Transmission Provider for any purpose.

Alternatively, they ask the Commission to clarify that as long as a 
transmission provider in good faith follows its published methodology 
for determining ATC and TTC it will be deemed not to be negligent.

Commission Conclusion

    The purpose of the force majeure provision in the pro forma tariff 
is to ensure that neither the customer nor the transmission provider is 
held in default in the event of an unpredictable and uncontrollable 
force majeure event. It was not the Commission's intention that the 
force majeure clause provide an avenue for a party to claim that it is 
excused from liability for its own negligence. A force majeure event 
does not include an act of negligence or intentional wrongdoing. The 
pro forma tariff will be changed accordingly.<SUP>385
---------------------------------------------------------------------------

    \385\ See Tex-La Electric Cooperative of Texas, Inc., 69 FERC 
para. 61,269 (1994) (requiring clarification that force majeure 
clause in electric transmission agreement does not excuse 
negligence); Avoca Natural Gas Storage, 68 FERC para. 61,045 (1994) 
(requiring modification of force majeure provision to ensure that 
parties would be liable for negligence or intentional wrongdoing).
---------------------------------------------------------------------------

    The purpose of the indemnification provision is to allocate the 
risks of a transaction, and the costs associated with those risks, to 
the party on whose behalf the transaction has been conducted, the 
transmission customer. As the tariff does not obligate the customer to 
perform services on behalf of the transmission provider, there is no 
comparable basis for imposing an indemnification obligation on the 
transmission provider.<SUP>386
---------------------------------------------------------------------------

    \386\ The Commission notes that in the past it may have accepted 
agreements containing gross negligence in force majeure and 
indemnification provisions. Consistent with the Commission's general 
policy of not abrogating existing contracts, we leave those 
provisions undisturbed.
---------------------------------------------------------------------------

    As is explained in the Final Rule, the Commission does not believe 
it appropriate to extend the indemnification obligation so that it 
would apply even in cases where the transmission provider has been 
negligent. The contention that electric transmission outages are either 
more frequent or more costly than gas outages does not serve to 
distinguish the electric transmission situation from the gas pipeline 
cases in which the Commission has found that indemnification clauses 
should not protect the pipeline owner from its own negligence.<SUP>387 
In either case, it would be inappropriate to require the customer to 
indemnify the transmission provider from damages arising from the 
transmission provider's own negligence. We note, however, that 
liability is a separate issue from indemnification. Despite the absence 
of indemnification protection, there is nothing in the indemnification 
provision that would preclude transmission providers from relying on 
the protection of state laws, when and where applicable, protecting 
utilities or others from claims founded in ordinary negligence.
---------------------------------------------------------------------------

    \387\ See, e.g., Pacific Interstate Offshore Company, 62 FERC 
para. 61,260 at 62,733-734 (1993) (requiring amendment of 
indemnification provisions that required indemnification except in 
cases of ``gross negligence'').
---------------------------------------------------------------------------

    With respect to the issue of consequential and indirect damages, 
the indemnification provision already provides protection to the 
transmission provider from consequential and indirect damage claims by 
third parties except in cases of negligence or intentional wrongdoing 
by the transmission provider. The Commission sees no need to further 
extend this protection. Again, we note that liability is a separate 
issue from indemnification, and that nothing in these provisions 
precludes transmission providers or customers from relying, when and 
where such law is applicable, on the protection of statutes or other 
law protecting parties from consequential or indirect damages.
    Furthermore, we will not revise the pro forma tariff, as requested 
by CSW Operating Companies, to provide that a transmission provider 
will not be liable for errors in an estimate made in good faith or in 
accordance with its published procedure. We believe that a utility 
should have no different a liability standard for operating an OASIS 
than for its other operations.<SUP>388
---------------------------------------------------------------------------

    \388\ See, e.g., Texas Eastern Transmission Corporation, 62 FERC 
para. 61,015 at 61,107 (1993).
---------------------------------------------------------------------------

6. Umbrella Service Agreements
    The Commission received requests for clarification regarding this 
issue, which was not specifically addressed by the Commission in the 
Final Rule.

Rehearing Requests

    SoCal Edison argues that it is too burdensome to require a separate 
Completed Application and a separate Service Agreement to be executed 
for each individual service transaction for short-term firm and non-
firm transmission service (and filed with the Commission). SoCal Edison 
contends that requiring a separate service agreement for each short-
term firm transaction to be filed with the Commission will stifle 
transactions in the short-term market. It indicates that it suggested a 
simpler approach in Docket No. ER96-222-000 that would establish a non-
transaction specific Service Agreement and a Completed Application that 
would contain the specific transaction information, but would not be 
filed with the Commission, but would be made available for 
audit.<SUP>389
---------------------------------------------------------------------------

    \389\ To date, the Commission has only issued a suspension order 
in this proceeding.
---------------------------------------------------------------------------

Commission Conclusion

    SoCal Edison misinterprets the tariff provisions regarding service 
agreements for non-firm point-to-point transmission service. Tariff 
section 14.5 details the treatment of service agreements for non-firm 
transmission service:

    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. 
(Emphasis added)

    Moreover, in tariff section 18 (Procedures for Arranging for Non-
Firm Point-To-Point Transmission Service) requires that a separate 
service agreement be executed for each individual service transaction 
as claimed by SoCal Edison. In the pro forma tariff, the Commission 
established a non-transaction specific (or ``umbrella'') service 
agreement in an attempt to streamline the application procedures for 
non-firm point-to-point transmission service. Therefore, the service 
agreement for non-firm point-to-point transmission service need only be 
executed and filed with the Commission once, when the transmission 
customer first applies for non-firm point-to-point transmission 
service. Subsequent non-firm transactions by the same customer only 
require the submission of a completed application (as provided in 
tariff sections 18.1 and 18.2) by that customer, which will be 
submitted via the transmission provider's OASIS (when the OASIS is 
fully implemented). Accordingly, no changes are required to

[[Page 12348]]

the application procedures for non-firm point-to-point service.
    However, we do find SoCal Edison's arguments persuasive that 
streamlined procedures should also be applied to applications for firm 
point-to-point transmission service with a duration of less than one 
year (short-term firm). We agree that there is no compelling reason to 
require the submission of separate service agreements for every short-
term firm transaction. Accordingly, we will adopt an ``umbrella'' 
service agreement approach (as is currently used for non-firm point-to-
point transactions) and require a service agreement of general 
applicability to be filed with the Commission when the first short-term 
firm transaction is arranged between the transmission provider and 
customer.
    In order to facilitate an umbrella service agreement approach for 
short-term firm transmission service, minor modifications have been 
made to several sections of the pro forma tariff <SUP>390 as well as to 
Attachment A (Form of Service Agreement For Firm Point-To-Point 
Transmission Service). Notably, pages 3 and 4 of the service agreement, 
containing transaction specific information, is now required only for 
long-term firm point-to-point transmission service.
---------------------------------------------------------------------------

    \390\ See changes to tariff sections 1.33, 1.34, 13.4, 13.7 and 
17.3.
---------------------------------------------------------------------------

7. Other Tariff Provisions
a. Minimum and Maximum Service Periods
    In the Final Rule, the Commission adopted a one-day minimum term 
for firm point-to-point service.<SUP>391 The Commission also concluded 
that it will not specify a maximum term for either firm point-to-point 
or network transmission service. However, the Commission modified the 
tariff to require that an application for transmission service specify 
the length of service being requested.
---------------------------------------------------------------------------

    \391\ FERC Stats. & Regs. at 31,752-53; mimeo at 346-47.
---------------------------------------------------------------------------

Rehearing Requests

    CCEM states that a competitive market for hourly trades should be 
allowed to develop (transmission and ancillary services). It argues 
that contrary to the Commission's goal of comparability, the Rule 
effectively allows only incumbent utilities to participate in hourly 
markets on behalf of their own or network loads (citing section 13.1 of 
the pro forma tariff).
    American Forest & Paper argues that firm and non-firm service 
should be made available on an hourly basis and that the Commission 
should assure that utilities make non-firm service available.

Commission Conclusion

    It is unclear as to what hourly ``trades'' CCEM is referring. If 
CCEM is referring to off-system sales, the transmission provider is 
obligated to take transmission for any off-system sales under point-to-
point transmission service under its tariff. Inasmuch as the tariff 
does not require the provision of hourly firm transmission, in order to 
provide itself with hourly firm transmission, the transmission provider 
would either: (1) reserve firm point-to-point service on a daily basis 
in order to participate in the hourly market or (2) propose in a 
section 205 filing to modify its tariff to voluntarily provide hourly 
firm point-to-point service. Under either circumstance, comparability 
would be maintained as all point-to-point customers would have equal 
access to the hourly market.
    If CCEM is referring to purchases, hourly economy purchases by the 
transmission provider on behalf of its native load customers are also 
available on a comparable basis to network customers. However, if CCEM 
is referring to specific purchases made on behalf of a particular 
wholesale customer, this resale must be provided under point-to-point 
transmission service, as described above.
    The Commission has rejected hourly firm point-to-point transmission 
service as a mandatory service to be provided under the Tariff.<SUP>392 
Many entities would not oppose hourly firm service if afforded a lower 
priority, i.e., if they were curtailed before longer-term firm 
services. However, with this lower priority there may be little or no 
difference between the pro forma tariff non-firm service and 
curtailable firm hourly service. The Commission adopted the one-day 
minimum term for firm service to address concerns that customers would 
engage in ``cream skimming'' by taking firm service only during the 
hours at the daily peak while taking non-firm service for other hours, 
and thereby avoiding paying a fair share of the costs of the 
transmission system. However, this does not mean that the Commission 
would not allow such services if voluntarily proposed by a transmission 
provider.
---------------------------------------------------------------------------

    \392\ FERC Stats. & Regs. at 31,752; mimeo at 346.
---------------------------------------------------------------------------

    Finally, in response to American Forest & Paper, the transmission 
provider has every incentive to make non-firm service available to all 
eligible customers in order to benefit native load customers, as the 
revenues generated by this service are typically used as a revenue 
credit to offset the costs of providing firm service. In addition, 
parties may raise concerns with the Commission in a section 206 
complaint if the transmission provider offers non-firm transmission 
service in a non-comparable, i.e., unduly discriminatory fashion.
b. Amount of Designated Network Resources
    In the Final Rule, the Commission indicated that it will not change 
the limitation on the amount of resources a network customer may 
designate. <SUP>393 The Commission explained that a transmission 
provider is required to designate its resources and is subject to the 
same limitations required of any other network customer.
---------------------------------------------------------------------------

    \393\ FERC Stats. & Regs. at 31,753-54; mimeo at 349-50.
---------------------------------------------------------------------------

    The Commission further explained that limiting the amount of 
resources to those that the customer owns or commits to purchase will 
protect a utility from having to incur costs that are out of proportion 
to the customer's load.
    With respect to the allocation of interface capacity under network 
service, the Commission clarified that a customer is not limited to a 
load ratio percentage of available transmission capacity at every 
interface. It explained that a customer may designate a single 
interface or any combination of interface capacity to serve its entire 
load, provided that the designation does not exceed its total load.

Rehearing Requests

    A number of entities state that section 30.8 of the pro forma 
tariff should be clarified to conform to the Final Rule preamble. The 
preamble states that a network customer should not be limited to a load 
ratio percentage of available transmission capacity at every interface, 
but may designate a single interface or any combination of interface 
capacity to serve its entire load, provided that the designation does 
not exceed its total load. However, they point out that section 30.8 of 
the pro forma tariff provides that 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 ratio 
share.<SUP>394
---------------------------------------------------------------------------

    \394\ E.g., NRECA, Blue Ridge, TDU Systems, Cleveland, AEC & 
SMEPA, Wisconsin Municipals, TAPS.
---------------------------------------------------------------------------

    TAPS and Wisconsin Municipals ask the Commission to clarify the 
inconsistency by deleting the phrase ``Ratio Share'' at the end of the 
section 30.8. TAPS argues that section 30.8 of

[[Page 12349]]

the tariff conflicts with the preamble, other sections of the tariff 
itself (see section 28), and recent Commission orders (Wisconsin Public 
Service Corporation, 74 FERC para. 61,022 at 61,064 and FMPA v. FPL, 67 
FERC 61,167 at 61,484). It further argues that load ratio restrictions 
on total interface usage would expand the market power of transmission 
providers.
    EEI and Southern state that under section 30.8 and the related 
preamble language, it is unclear how the concept of load ratio share 
should be applied in the context of interface capacity, (i.e., is the 
network customer entitled to a load ratio share of available 
transmission capacity or total transmission capacity for an 
interface?). They argue that ATC is the appropriate basis for 
calculating shares of interface capacity and state that the Commission 
should specify that network service entitles the user to a load ratio 
share of the available capacity of each interface. EEI adds that if 
sufficient interface capacity is available, a request by a network 
customer to use available interface capacity to bring in resources for 
network load in excess of its load ratio share of the interface should 
be accommodated under the point-to-point tariff and treated on a first-
come, first-served basis.<SUP>395
---------------------------------------------------------------------------

    \395\ TAPS filed a response opposing these requests for 
rehearing. (TAPS Response). As we explained above, we will accept 
the TAPS Response.
---------------------------------------------------------------------------

    Florida Power Corp states that ``[i]n order to clarify that network 
customers may obtain transmission service over the transmission 
provider's interfaces in excess of their load ratio shares, the 
Commission should clarify that additional interface capability may be 
purchased (subject to availability) as firm point-to-point transmission 
service.'' (Florida Power Corp at 29).

Commission Conclusion

    We agree that the pro forma tariff should be conformed to the 
preamble language in the Final Rule so that the interface capacity is 
limited to the customer's total load, not a load ratio share. This is 
consistent with the Commission's recent rehearing order in FMPA v. FPL:
    We clarify that the phrase ``that is, up to its share of the load, 
3%'' was not intended to limit FMPA's use of each interface to a 
discrete ratio (3%). Rather, FMPA, as well as Florida Power, can use 
each interface, if capacity is available, to service its entire network 
load. If the interface is [constrained] [sic], they will either pay 
redispatch costs or expansion costs based on their load ratio 
share.<SUP>[396]
---------------------------------------------------------------------------

    \396\ 74 FERC at 61,018.
---------------------------------------------------------------------------

c. Eligibility Requirements
    In the Final Rule, the Commission found that a non-discriminatory 
open access transmission tariff must be made available, at a minimum, 
to any entity that can request transmission services under section 211 
and to foreign entities. <SUP>397
---------------------------------------------------------------------------

    \397\ FERC Stats. & Regs. at 31,754; mimeo at 351.
---------------------------------------------------------------------------

Rehearing Requests

    VT DPS and Valero state that the Final Rule does not appear to 
contemplate that marketers will buy network service or that one network 
service customer might serve a portion of the requirements of another 
network customer. Thus, they argue that network load can be double 
counted. To resolve this problem, they argue, service should be made 
available to suppliers rather than load, as provided in the NorAm NIS 
tariff, Section 1.5.

Commission Conclusion

    Power marketers are specifically named in the definition of 
Eligible Customer (Section 1.11), and nothing in the Network 
Integration Transmission Service prohibits marketers from serving 
customers and designating those customers' loads (or portions thereof) 
as the marketers' Network Loads.
    Additional rehearing requests regarding eligibility are addressed 
in Section IV.C.1. (Eligibility to Receive Non-discriminatory Open 
Access Transmission).
d. Two-Year Notice of Termination Provision
    In the Final Rule, the Commission deleted the notice of termination 
provision from the tariff.<SUP>398
---------------------------------------------------------------------------

    \398\ FERC Stats. & Regs. at 31,754-55; mimeo at 353.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
e. Termination of Service for Failure to Pay Bill
    In the Final Rule, the Commission stated that section 7.3 of the 
Final Rule pro forma tariff provides that in the event of a customer 
default, the transmission provider may, in accordance with Commission 
policy, file and initiate a proceeding with the Commission to terminate 
service.<SUP>399
---------------------------------------------------------------------------

    \399\ FERC Stats. & Regs. at 31,794; mimeo at 467.
---------------------------------------------------------------------------

Rehearing Requests

    El Paso asserts that the Commission does not have the authority to 
prohibit a transmission provider from terminating service to a customer 
that has failed to pay its bill until permission from the Commission 
has been obtained. It argues that the Commission does not have 
abandonment authority under the FPA.

Commission Conclusion

    El Paso is not correct. Under section 205 of the FPA, public 
utilities are allowed to effectuate changes in rates, charges, 
classification or service only after providing 60 days notice to the 
Commission and the public. Because a termination of service is clearly 
a change in service, public utilities must file notice of a termination 
60 days prior to the proposed effective date.
    In Portland General Electric Company, 75 FERC para. 61,310, reh'g 
denied, 77 FERC para. 61,171 (1996), we denied a requested waiver of 
section 35.15 of the Commission's Rules of Practice and Procedure to 
permit the utility to terminate service in the event of customer 
default. We indicated that we had previously explained the reasons for 
requiring public utilities to file notices of termination when seeking 
to discontinue service <SUP>400 and further explained that

    \400\ E.g., to protect wholesale purchasers--and, by extension, 
ultimate consumers--from losing service unjustly; to provide the 
Commission an opportunity to ensure that the termination is just and 
reasonable. 77 FERC at 61,171.

electricity is not just any commercial good or service. Rather, 
Congress in the Federal Power Act has charged us with ensuring that 
sales for resale or transmission of electricity in interstate 
commerce by public utilities take place at rates, terms and 
conditions that are just and reasonable.<SUP>[401]
---------------------------------------------------------------------------

    \401\ Id.
---------------------------------------------------------------------------

f. Definition of Native Load Customers
    The Commission defined the term ``Native Load Customers'' in 
section 1.19 of the pro forma tariff as:

    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.

Rehearing Requests

    The pro forma tariff defines native load customers as ``[t]he 
wholesale and retail power customers of the Transmission Provider. * * 
*'' Cooperative Power argues that the definition of native load 
customers should recognize that joint planning is a sufficient 
criterion, and that construction and operation by the

[[Page 12350]]

transmission provider should not be necessary for native load status to 
be conferred. It asserts that under joint planning, the loads of 
transmission-only customers are considered native, therefore the 
Commission should eliminate the word power from the definition.<SUP>402
---------------------------------------------------------------------------

    \402\ Dairyland filed a supplemental request for rehearing 
raising similar arguments. (Dairyland Supplement). We will accept 
this pleading as a motion for reconsideration, not as a request for 
rehearing, because it was not filed within the 30-day statutory 
period for rehearing requests. See 16 U.S.C. Sec. 8251(a).
---------------------------------------------------------------------------

    NRECA and TDU Systems state that traditional wholesale customers 
that have long been on the system, have assisted in paying for past 
expansions, and will likely continue to be captive to a provider's 
monopoly transmission service, should have ``native load equivalent'' 
rights if they take network or long-term firm service. If the 
transmission provider has planned and will plan in the future for a 
customer's full or partial needs, they argue that the customer should 
be treated as the equivalent of native load. They point out that 
section 1.19 of the tariff limits native load status only to wholesale 
power customers of the transmission provider.
    VA Com argues that the definition of native load in section 1.19 of 
the tariff should include existing distribution cooperatives and others 
who currently provide service to end users.

Commission Conclusion

    We reject Cooperative Power's suggestion to include transmission-
only point-to-point customers in the definition of native load. We note 
that network customers are provided with rights comparable to native 
load customers because the transmission provider includes their network 
resources and loads in its long-term planning horizon. However, a 
point-to-point transmission service customer is not similarly situated 
to native load and Network Customers. The Network service formula rate 
requires the Network customer to pay a load-ratio share of the costs of 
the transmission provider's transmission system on an ongoing basis, 
while a point-to-point transmission service customer is only 
responsible for paying on a contract demand basis over the contract 
term. The network customer and the native load of the transmission 
provider pay all the residual costs of the transmission system and face 
greater risks of rate fluctuations due to facility additions and 
variations in load of both its and other customers. In contrast, the 
point-to-point transmission service customer may be more transitory in 
nature electing shorter terms of service and specific forms of service 
tailored for discrete services over specific time periods that do not 
necessarily enter into the transmission provider's planning horizon. To 
the extent a transmission customer desires similar rights and cost 
responsibilities to a native load customer, it can always elect to take 
network service.
    We further note that, in granting a right of first refusal to 
existing customers, we afforded existing transmission only point-to-
point customers a priority to continue to use the transmission 
provider's system.
    VA Com's proposed change to the definition of native load was made 
in conjunction with its proposed change in the reservation priority 
(highest priority for ``native load'', followed by firm contract 
customers and lastly, non-firm customers). Because we are rejecting VA 
Com's proposed reservation priority (see Section IV.G.3.a. above), we 
will also reject its proposed conforming change to the definition of 
native load as proposed by VA Com.
g. Off-System Sales
    Regarding the unbundling of off-system sales, the Final Rule 
required that all bilateral economy energy coordination contracts 
executed before the effective date of Order No. 888 must be modified to 
require unbundling of any economy energy transaction occurring after 
December 31, 1996.<SUP>403 Concerning the treatment of revenues from 
transmission associated with off-system sales, the Commission stated in 
the Final Rule that revenue from non-firm services should continue to 
be reflected as a revenue credit in the derivation of firm transmission 
tariff rates.<SUP>404
---------------------------------------------------------------------------

    \403\ FERC Stats. & Regs. at 31,700; mimeo at 191.
    \404\ FERC Stats. & Regs. at 31,738; mimeo at 304.
---------------------------------------------------------------------------

Rehearing Requests

    Montana Power asserts that the Commission should clarify that off-
system sales that originate from generating plants or power purchases 
outside the transmission provider's system and do not use the 
transmission provider's transmission system should not be automatically 
assessed point-to-point charges.
    Maine Public Service asks the Commission to clarify that revenues 
from off-system sales are not to be credited where the sales do not use 
the transmission provider's system (referencing sections 1.44 and 8.1 
of the pro forma tariff). Maine Public Service states that it makes 
sales from Maine Yankee (which is not located on Maine Public Service's 
system) to customers not on its system and that it should not have to 
credit these sales revenues to its transmission customers.
    Wisconsin Municipals asks the Commission to clarify that the 
provision and level of revenue credits are rate issues and that if 
parties have negotiated provisions for revenue credits, the Final Rule 
cannot be used to avoid obligations undertaken in a settlement.

Commission Conclusion

    Utilities must take all transmission services for wholesale sales 
under new requirements contracts and new coordination services under 
the same tariff used by eligible customers. The Commission provided an 
extension until December 31, 1996, for utilities to take transmission 
service under the same tariff for their economy energy transactions, 
certain power pooling arrangements, and other multi-lateral 
arrangements.<SUP>405 The above criteria, however, only apply when a 
utility transmission system is being used to accommodate off-system 
sales. Therefore, a utility would not be required to take point-to-
point transmission service if its transmission system is not being used 
for the transaction.
---------------------------------------------------------------------------

    \405\ FERC Stats. & Regs. at 31,700; mimeo at 191.
---------------------------------------------------------------------------

    Maine Public Service's concern is misplaced. Maine Public Service 
states that certain of its sales do not use its own transmission system 
and that it pays other utilities for such transmission service. 
However, Section 8.1 only specifies the treatment of revenues the 
transmission provider receives from transmission service it provides 
itself when making third-party sales using point-to-point transmission 
service under its tariff. If Maine Public Service is not the 
transmission provider for these third-party sales, then Section 8.1 
does not apply to such transactions.
    Wisconsin Municipals' argument with respect to prior settlements 
has been previously addressed in Section IV.D.1.c.(2) (Energy Imbalance 
Bandwidth).
h. Requirements Agreements
    A detailed description of the Commission's unbundling requirements 
pertaining to requirements agreements is described below.

Rehearing Requests

    Blue Ridge requests that the Commission clarify the definitions of 
requirements, economy and non-economy energy coordination agreements. 
In addition, Blue Ridge

[[Page 12351]]

seeks clarification regarding which dates are to be used to distinguish 
between existing and new contracts (July 11, 1994 or July 9, 1996).

Commission Conclusion

    The definitions of economy and non-economy energy coordination 
agreements are addressed in section IV.F.4. (Bilateral Coordination 
Arrangements). With respect to Blue Ridge's concern regarding 
requirements agreements, we defined requirements contracts broadly in 
section 35.28(b)(1) of the Commission's regulations as ``any contract 
or rate schedule under which a public utility provides any portion of a 
customer's bundled wholesale power requirements.'' The definition is 
intended to encompass partial requirements service, since that service 
is intended to meet the bundled load requirements of a customer that is 
not provided from other sources such as self-generation or unit power 
purchases. In contrast, a non-economy energy coordination agreement is 
not intended to meet, by itself, the entirety of a customer's bundled 
power requirement or the residual partial power requirement of a 
customer. For example, a 50 MW unit power purchase or a long-term firm 
power purchase would supply long-term firm power but a customer would 
likely need an additional partial requirements agreement to supply the 
residual amount of its load requirement.
    Regarding Blue Ridge's request for clarification of the dates for 
new and existing agreements, the Commission explicitly stated in Order 
No. 888 that any bilateral wholesale coordination agreements executed 
after July 9, 1996 would be subject to the functional unbundling and 
open access requirements set forth in the Rule.<SUP>406 In addition, 
the Commission required that all bilateral economy energy coordination 
contracts executed on or before July 9, 1996 be modified to require 
unbundling of any economy energy transaction occurring after December 
31, 1996. The Commission permitted all non-economy energy bilateral 
coordination agreements executed before July 9, 1996 to continue in 
effect subject to section 206 complaints.
---------------------------------------------------------------------------

    \406\ FERC Stats. & Regs. at 31,729-30; mimeo at 277-78.
---------------------------------------------------------------------------

    For the purpose of distinguishing between existing and new 
wholesale requirements contracts and for stranded investment recovery 
provisions, the Commission established July 11, 1994 as the applicable 
date.<SUP>407 For a utility to recover stranded investment costs in new 
requirements contracts, it must include explicit provisions in the 
contract for stranded investment recovery. Existing requirements 
contracts would not need a similar provision to be eligible for 
stranded investment recovery.<SUP>408 Utilities are required to 
unbundle all new requirements contracts. The requirement that utilities 
unbundle existing wholesale requirements contracts is for informational 
purposes and will enable existing requirements customers to evaluate 
and compare the transmission component of existing contracts to 
alternative contracts prior to the existing contracts' expiration 
dates.
---------------------------------------------------------------------------

    \407\ Mimeo at 769.
    \408\ FERC Stats. & Regs. at 33,110 and 31,804-05; mimeo at 85 
and 497-98.
---------------------------------------------------------------------------

i. Use of Distribution Facilities
    The Commission received requests for clarification regarding this 
issue which was not specifically addressed by the Commission in the 
Final Rule.

Rehearing Requests

    CSW Operating Companies asks the Commission to make clear that to 
the extent a transmission provider makes available to transmission 
customers the use of distribution facilities, the terms governing the 
use of and the charges for such use should be set forth in the 
customer's service agreement.

Commission Conclusion

    Utilities are free to include customer-specific terms and 
conditions or terms and conditions limited to certain customers (e.g., 
a distribution charge) in a customer's service agreement and/or the 
network customer's network operating agreement.
j. Losses
    The Commission received requests for clarification regarding this 
issue which was not specifically addressed by the Commission in the 
Final Rule.

Rehearing Requests

    VT DPS asserts that network customers should not have to bear 
losses twice--the tariffs allow collection of losses over all network 
load, even that supplied by behind the meter generation. It argues that 
losses should only be paid on power actually transmitted over the 
company's system.

Commission Conclusion

    The pro forma tariff neither specifies the applicable Real Power 
Loss factors (see tariff section 28.5) nor the demand levels to which 
the loss factors should be applied. Accordingly, concerns regarding the 
loss calculation for a customer should be raised when the transmission 
provider files with the Commission a service agreement for a network 
customer.
k. Modification of Non-Rate Terms and Conditions
    The Commission's requirements pertaining to modification of non-
rate terms and conditions is described below.

Rehearing Requests

    TAPS asserts that the language of section 35.28(c)(1)(v) and the 
preamble of Order No. 888 are inconsistent. TAPS argues that the 
Commission should require a demonstration of consistency with and 
superiority to the terms and conditions of the pro forma tariff and 
indicate that it will not allow deviations that seek to withdraw the 
minimum terms and conditions of non-discriminatory transmission. 
According to TAPS, the Commission should also clarify that the 
Commission will not let onerous tariff terms creep in through the back 
door, i.e., through service agreements. TAPS also maintains that the 
Commission should not allow transmission providers to use conformity as 
an excuse to evade commitments.

Commission Conclusion

    Order No. 888 allows a utility the flexibility to propose, after 
the compliance tariffs go into effect, to modify non-rate terms and 
conditions of the tariff if it can ``demonstrate[] that such terms * * 
* are consistent with, or superior to, those in the compliance 
tariff.'' These are the same principles that are referenced in the 
regulation language (deviations allowed if the transmission provider 
can demonstrate the deviation is consistent with the principles of 
Order No. 888). While utilities are free to file revised tariffs after 
their compliance filings, any filing including service agreements will 
be carefully reviewed by the Commission to assure that the revised 
tariffs and service agreements are just and reasonable and consistent 
with the principles of Order No. 888.
    With regard to TAPS' concern about transmission providers evading 
commitments, we reiterate that we will not require abrogation of 
existing contracts (and the commitments reflected therein) except on a 
case-specific basis.
l. Miscellaneous Tariff Modifications
(1) Ancillary Services
    The Commission explained that the pro forma tariff incorporates 
conforming revisions consistent with the

[[Page 12352]]

determinations discussed in the Final Rule.<SUP>409
---------------------------------------------------------------------------

    \409\ FERC Stats. & Regs. at 31,763; mimeo at 378.
---------------------------------------------------------------------------

(2) Clarification of Accounting Issues
    In the Final Rule, the Commission offered clarifications on the 
Final Rule pro forma tariff requirements and certain other accounting 
issues related to the Final Rule.<SUP>410
---------------------------------------------------------------------------

    \410\ FERC Stats. & Regs. at 31,763-64; mimeo at 379-80.
---------------------------------------------------------------------------

(a) Transmission Provider's Use of Its System (Charging Yourself)
    In the Final Rule, the Commission stated that the purpose of 
functional unbundling is to separate the transmission component of all 
new transactions occurring under the Final Rule pro forma tariff, 
thereby assisting in the verification of a transmission provider's 
compliance with the comparability requirement. With respect to off-
system sales, the Commission stated that the transmission provider 
would book to operating revenue accounts those revenues received from 
the customer to whom it made the off-system sale.<SUP>411 The 
Commission required that the transmission service component and energy 
component of those revenues be recorded in separate subaccounts of 
Account 447, Sales for Resale.
---------------------------------------------------------------------------

    \411\ FERC Stats. & Regs. at 31,764; mimeo at 380-81.
---------------------------------------------------------------------------

Rehearing Requests

    APPA argues that the revenue from the transmission component of all 
off-system uses must be included in the credit if comparability is to 
be achieved.
    APPA also argues that booking revenue credits to Account 447 for a 
test year reduction does not ensure timely receipt by customers. It 
asserts that a monthly pass-through to all firm transmission customers 
is needed.
    APPA further argues that a properly functioning revenue credit does 
away with the perception of disparate treatment of network and point-
to-point customers. Similarly, TDU Systems argues that comparability 
requires that revenues attributable to transmission owners' use of 
their transmission systems be flowed through to customers' benefit 
immediately so that transmission owners and customers receive 
comparable price signals with regard to their uses of the system.

Commission Conclusion

    The precise methodology to be used to credit revenues from off-
system sales for the benefit of the tariff customers should be 
addressed in the compliance filing proceedings and will depend on the 
particular rate design methodology that is ultimately employed. APPA's 
proposed monthly pass-through of revenue credits raises potential 
issues including: (1) use of estimates versus actuals; (2) the 
appropriate time period to be utilized; and (3) firm versus non-firm 
distinctions. Accordingly, the issue of determining appropriate revenue 
credits is properly left for case-by-case determinations. However, we 
agree with APPA that revenue from the transmission component of all 
off-system uses of the transmission system (whether by the transmission 
provider or a transmission customer) must be treated on a comparable 
basis, whether through rate design or through revenue credits.
(b) Facilities and System Impact Studies
    In the Final Rule, the Commission explained that comparability 
mandates that to the extent a transmission provider charges 
transmission customers for the costs of performing specific facilities 
studies or system impact studies related to a service request, the 
transmission provider also must separately record the costs associated 
with specific studies undertaken on behalf of its own native load 
customers, or, for example, for making an off-system sale.<SUP>412
---------------------------------------------------------------------------

    \412\ FERC Stats. & Regs. at 31,764; mimeo at 381-82.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
(c) Ancillary Services
    In the Final Rule, the Commission indicated that, at this time, it 
was not convinced that the amounts involved or the difficulty 
associated with measuring the cost of ancillary services warrants a 
departure from our present accounting requirements.<SUP>413
---------------------------------------------------------------------------

    \413\ FERC Stats. & Regs. at 31,764-65; mimeo at 382-83.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
(3) Miscellaneous Clarifications
(a) Electronic Format
    In the Final Rule, the Commission required that public utilities, 
in addition to complying with the requirements of Part 35, submit a 
complete electronic version of all transmission tariffs and service 
agreements in a word processor format, with the diskette labeled as to 
the format (including version) used, initially and each time changes 
are filed.<SUP>414
---------------------------------------------------------------------------

    \414\ FERC Stats. & Regs. at 31,766; mimeo at 386.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
(b) Administrative Changes
    In the Final Rule, the Commission set forth a number of tariff 
modifications that it indicated needed no further explanation.<SUP>415
---------------------------------------------------------------------------

    \415\ FERC Stats. & Regs. at 31,766-67; mimeo at 386-88.
---------------------------------------------------------------------------

8. Specific Tariff Provisions
    The Commission attached a pro forma tariff to the Final Rule as 
Appendix D. A number of entities have sought rehearing of various 
sections of that pro forma tariff. Their arguments and the Commission's 
responses are set forth below.

Rehearing Requests

    Oklahoma G&E asks that the Commission add a definition for 
``Interconnection'' that would be an interface where one or more points 
of delivery or points of receipt are located.

Commission Conclusion

    We disagree with Oklahoma G&E that there is a need to add a 
definition for ``Interconnection'' to the Final Rule pro forma tariff. 
Oklahoma G&E has not supported its need for the proposed change and has 
failed to identify any potential problems that may result if its 
definition is not included.

Sections 1.12, 15.4 and 32.4

Rehearing Requests

    Cajun argues that the Commission should mandate joint planning in 
the development of Facilities Studies. It alleges that a transmission 
provider's independent long-range plans frequently include longer, 
higher voltage facilities than are needed for the transmission 
customers' requirements. It further alleges that absent mandatory joint 
transmission planning, the transmission customers will always be paying 
for the incremental capacity cost of transmission enhancements that 
only fit into the Transmission Provider's independent long-range plans.

Commission Conclusion

    A joint planning mandate as recommended by Cajun, NRECA and others 
is beyond the scope of this proceeding. However, the Commission 
encourages 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. Moreover, on a regional 
basis, the Commission encourages the formation

[[Page 12353]]

of RTGs and ISOs to represent the needs of all participants in a region 
in the planning process.
Section 1.14

Rehearing Requests

    CCEM asserts that the term Good Utility Practice is vague. It 
argues that the Commission should delete the reference to regional 
practices, but if it does not, the term should be clearly defined in 
each utility's tariff.

Commission Conclusion

    The Commission recognizes that unique operating practices and 
conditions exist on a regional basis throughout the industry. 
Accordingly, the Commission permits certain deviations to the non-price 
terms and conditions of the tariff. In the Final Rule, we stated that 
any proposed modifications by the utility to the tariff to recognize 
regional operations and practices must be demonstrated to be 
reasonable, generally accepted in the region, and consistently adhered 
to by the transmission provider.<SUP>416
---------------------------------------------------------------------------

    \416\ FERC Stats. & Regs. at 31,770; mimeo at 397-98. The 
Commission has applied its approach to regional practices in filings 
made in compliance with Order No. 888. See, e.g., American Electric 
Power Service Corporation, et al., 78 FERC para. 61,070 (1997); 
Allegheny Power System, Inc., et al., 77 FERC para. 61,266 (1996); 
Atlantic City Electric Company, et al., 77 FERC para. 61,144 (1996).
---------------------------------------------------------------------------

Sections 1.22 and 1.25

Rehearing Requests

    Blue Ridge requests clarification that a portion of a designated 
network resource need not consist of the entirety of a generating unit.

Commission Conclusion

    Blue Ridge's request for clarification in the definition of 
``Network Load'' in Tariff Section 1.22 and ``Network Resource'' in 
Tariff Section 1.25 is not necessary. Blue Ridge's concerns are based 
on the mistaken premise that a designated network resource must consist 
of the entirety of a generating unit. Tariff sections 1.25 and 30.1 
explicitly specify that a network resource can be a portion of a 
generating resource or unit. Indeed, the Commission recently emphasized 
this point:

    Ohio Cooperatives have disregarded the fact that a designated 
resource can be a part of a unit. In this example, Ohio Cooperatives 
would make two network designations for the 300 MW unit: a 100 MW 
designation for the 100 MW load on one system and a 200 MW 
designation for the 200 MW on the other system.<SUP>417
---------------------------------------------------------------------------

    \417\ Order On Non-Rate Terms and Conditions, 77 FERC para. 
61,144 (mimeo at 15-16) (1996).
---------------------------------------------------------------------------

Sections 1.25 and 30.1

Rehearing Requests

    TDU Systems asserts that these sections should not be read to 
require assignment of specific Network Resources to specific control 
areas. They state that multiple control area network customers need to 
be able to dispatch their resources economically to serve their loads. 
They argue that the Commission would be in error to require that a 
transmission customer's resources be segmented if they are being 
dispatched to serve network load in one of several control areas and 
once so segmented, sales from such units be considered either third-
party sales or become interruptible as to network load in a second 
control area and thus are not deemed Network Resources. They further 
argue that TDU systems with loads and resources in multiple control 
areas must be allowed to designate as Network Resources for each 
control area the totality of their resources which meet the owned or 
purchased requirements of section 1.25.
    TDU Systems argues that these sections should be revised to include 
resources that are leased by a network customer on terms tantamount to 
ownership, or which, at a minimum, afford the network customer a first 
call right to that generating resource.

Commission Conclusion

    TDU Systems' proposed revision to recognize leased resources 
appears reasonable and we revise these sections of the pro forma 
tariff, in relevant part, as follows (new text underlined, deleted text 
in brackets):

1.25  Network Resource: Any designated generating resource owned, [or] 
purchased or leased by a Network Customer under the Network Integration 
Transmission Service Tariff.
30.1  Designation of Network Resources: Network Resources shall include 
all generation owned, [or] purchased or leased by the Network Customer 
designated to serve Network Load under the Tariff.

Sections 1.33 and 1.34

Rehearing Requests

    CCEM states that sections 1.33 and 1.34 should be changed to 
facilitate umbrella service agreements that include all points of 
receipt and delivery on a transmission provider's system.

Commission Conclusion

    Consistent with our ruling in section IV.G.6 (Umbrella Service 
Agreement) regarding umbrella type service agreements for short-term 
firm point-to-point transmission service, we will modify sections 1.33 
and 1.34 to require that Points of Receipt and Points of Delivery be 
specified in the service agreement for only Long-Term (more than one 
year) Firm Point-to-Point Transmission service.

Section 1.47

Rehearing Requests

    Wisconsin Municipals asks the Commission to clarify that a utility 
is not prevented from including the load of interruptible customers in 
the denominator of the fraction used to perform the load ratio 
calculation. It claims that this is important in Wisconsin where the 
transmission system is planned without regard to the distinction 
between firm and interruptible power customers (interruptible customers 
are not subject to interruption for transmission reasons).

Commission Conclusion

    The treatment of interruptible loads in the planning and operation 
of the Wisconsin transmission grid present a unique, case-specific 
situation that is best addressed on a case-by-case basis. As the 
Commission stated in the Final Rule:

all tariffs need not be ``cookie-cutter'' copies of the Final Rule 
tariff. Thus, under our new procedure, ultimately a tariff may go 
beyond the minimum elements in the Final Rule pro forma tariff or 
may account for regional, local, or system-specific factors. The 
tariffs that go into effect 60 days after publication of this Rule 
in the Federal Register will be identical to the Final Rule pro 
forma tariff; however, public utilities then will be free to file 
under section 205 to revise the tariffs, and customers will be free 
to pursue changes under section 206.<SUP>[418]
---------------------------------------------------------------------------

    \418\ FERC Stats. & Regs. at 31,770 n. 514; mimeo at 399 n. 514.
---------------------------------------------------------------------------

Section 1.48

Rehearing Requests

    Oklahoma G&E asks the Commission to clarify that the term 
``Transmission Service'' as used in the pro forma tariff includes 
service provided on a network basis as well as on a point-to-point 
basis.

Commission Conclusion

    The Commission used the term ``Transmission Service'' throughout 
the pro forma tariff to refer only to point-to-point service and not 
network service. We also note that the term ``transmission service'' 
(in lower case), which is also used throughout the pro

[[Page 12354]]

forma tariff, was used to refer to both point-to-point and network 
service. Oklahoma G&E has not identified any problems associated with 
our use of these terms and therefore has not supported its proposed 
modification.

Section 1.49

Rehearing Requests

    Santa Clara and Redding state that the transmission system is 
defined as facilities owned, controlled or operated and that this could 
result in the same transmission facilities being the part of the 
transmission system of two entities (e.g., COTP, which is owned by 
TANC, but operated by Western Area Power Administration (WAPA)). They 
ask the Commission to clarify that only one such entity should have the 
obligation to provide transmission service.

Commission Conclusion

    This presents a fact-specific situation that is best addressed on a 
case-by-case basis. This situation would appear to arise for WAPA and 
TANC only if either utility receives a request for reciprocal 
transmission service or if either utility files a voluntary tariff. The 
appropriate entity to include the COTP facility in its transmission 
system for purposes of a transmission tariff may depend upon the 
circumstances of the transmission request. Therefore, a resolution of 
this question is appropriately deferred until such time as reciprocal 
service using the COTP facility is requested.

Section 3

Rehearing Requests

    CCEM asks the Commission to clarify that a transmission customer 
may switch its supplier of ancillary services.

Commission Conclusion

    The Final Rule requires that transmission customers obtain all 
necessary ancillary services for their transactions. They must purchase 
certain of these services from the transmission provider, but can self 
supply or obtain certain services from a third party. Consistent with 
these requirements, a transmission customer may switch suppliers of 
ancillary services not required to be provided by the transmission 
provider if it continues to demonstrate that it satisfies its ancillary 
service obligations.

Section 5.1

Rehearing Requests

    ConEd points out that this section applies to Transmission Service, 
which the tariff defines to mean point-to-point service only. It 
requests that this section be clarified to include network service.

Commission Conclusion

    The use of the term ``Transmission Service'' in section 5.1 of the 
pro forma tariff was an inadvertent error. We will change the term 
``Transmission Service'' used in section 5.1 to ``transmission 
service'' so as to include both point-to-point and network transmission 
service.

Section 6

Rehearing Requests

    CCEM asks the Commission to require that the text of the required 
sworn statement by non-transmission owning entities that they are not 
assisting an Eligible Customer be included in the tariff.

Commission Conclusion

    We will deny CCEM's request as unnecessary. The Commission does not 
believe that it must mandate the precise text of the required sworn 
statement. Rather, the entity requesting transmission service properly 
has the burden of explaining in a sworn statement the circumstances of 
its service request, including on whose behalf it may be requesting 
service (for itself or for another party).

Section 8

Rehearing Requests

    CCEM argues that, consistent with Commission policy for natural gas 
pipelines, transmission providers should be required to refund all 
``penalties'' that are in excess of the costs incurred to balance 
transmitting system operations (citing Transco, 55 FERC para. 61,446 at 
62,372 (1991) and TETCO, 62 FERC para. 61,015 at 61,117 (1993)).

Commission Conclusion

    CCEM's argument is premature. Order No. 888 did not establish a 
rate or a penalty for Energy Imbalance Service. CCEM is free to raise 
this concern at such time as utilities file their proposed rates for 
Energy Imbalance Service.

Section 11

Rehearing Requests

    CCEM contends that an unconditional and irrevocable letter of 
credit is extremely costly to obtain and could be used as subterfuge 
for discriminatorily denying service. CCEM argues that if an 
irrevocable letter of credit is used, a transmission provider should 
not be able to draw on it until it tenders a bill that has been 
improperly refused. (CCEM attached a proposed conditional letter of 
credit to its rehearing request). Several entities argue that a letter 
of credit should not be required for existing customers with a 
satisfactory credit history and should only apply to new customers or 
those with a history of payment delinquency.<SUP>419
---------------------------------------------------------------------------

    \419\ E.g., Santa Clara, Redding, TANC.
---------------------------------------------------------------------------

Commission Conclusion

    While a transmission provider may require an unconditional and 
irrevocable letter of credit, if a customer believes that the 
transmission provider unreasonably rejected an alternative security 
proposal, it may seek relief through the dispute resolution procedures 
established in Tariff Section 12. Moreover, if a customer believes a 
transmission provider is attempting to use the unconditional and 
irrevocable letter of credit in an unduly discriminatory manner, it may 
file a complaint raising such concern in a section 206 filing.

Section 12

Rehearing Requests

    According to Public Service Co of CO, the dispute resolution 
procedures: (1) Should allow a party to appeal an arbitration award on 
the basis that arbitrators have misinterpreted the requirements of the 
pro forma tariff and (2) where a utility is a member of an RTG, should 
allow the RTG dispute resolution procedures to be exclusive. Otherwise, 
Public Service Co of CO argues, entities may perceive that the 
Commission's procedures are more favorable than the RTG's and decide 
not to join. Moreover, it asserts that when a utility that is a member 
of an RTG has a dispute with a customer that is a non-member, the 
customer's forum should be the Commission, or the RTG's procedures if 
those procedures apply to non-members.
    Dispute Resolution Associates asks the Commission to require that 
prior to submission of disputes for arbitration or Commission 
disposition, disputants should be required to pursue a mediated 
resolution with a qualified individual. If unsuccessful, it states that 
parties can elect arbitration or Commission disposition. If successful, 
it states that parties will have avoided litigation related costs and 
will not have jeopardized their ongoing business relationship. Dispute 
Resolution Associates also argues that representatives at all 
negotiating sessions should be authorized to enter into an agreement 
and asks that the Commission clarify that dispute resolution is one of 
the minimum requirements of the Final Rule. It also asks that the 
Commission require that any filed separate retail transmission

[[Page 12355]]

tariffs must include section 12 type dispute resolution procedures.

Commission Conclusion

    Concerning the first issue raised by Public Service Co of CO, even 
if the arbitrator misinterprets the requirements of the pro forma 
tariff, the dispute resolution procedures require such decision (as it 
affects terms and conditions of service) to be filed with the 
Commission. Section 12.2 provides:

    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.

    As to Public Service Co of CO's second concern, a utility's 
membership in an RTG with its own Dispute Resolution Procedures 
presents a fact specific situation to which a generic response is not 
appropriate. Whether both parties to a dispute are members of the RTG 
or only one of the parties is a member may have some bearing on which 
set of Dispute Resolution Procedures should apply.
    Regarding Dispute Resolution Associates concerns, a utility is free 
to propose an initial process using ``mediated resolution with a 
qualified individual'' prior to using the Dispute Resolution 
Procedures. However, we see no need to modify the tariff to introduce 
such a proposed requirement as the Commission is not aware of other 
parties similarly claiming excessive costs or the threat of 
``jeopardizing ongoing business relationship[s]'' due to the present 
Dispute Resolution Procedures. Finally, any attempts to delete the 
Dispute Resolution Procedures from any tariff on file with the 
Commission would require the transmission provider to demonstrate that 
its proposed modifications are consistent with or superior to the pro 
forma tariff terms and conditions.

Section 13.2

Rehearing Requests

    CCEM asserts that the term ``reserved service'' should be changed 
to ``requested service.'' Utilities For Improved Transition and Florida 
Power Corp assert that the limitations on unconditional reservations 
are too stringent and that the Commission should modify the third 
sentence of section 13.2 to provide: ``If the Transmission System 
becomes oversubscribed, requests for longer-term service may preempt 
requests for shorter-term service up to a time period before the 
requested commencement of service that is equal to the requested term 
of service.''

Commission Conclusion

    We will deny CCEM's request to replace the term ``reserved 
service'' in tariff section 13.2 with ``requested service.'' CCEM has 
not attempted to identify any uncertainties caused by the current 
wording of this section or explain any improvements that its proposed 
change would make.
    Utilities For Improved Transition and Florida Power Corp's proposal 
to revise the deadline for when reservations for short-term firm 
transmission become unconditional is contrary to the Commission's 
intent in adopting the conditional reservation approach for short-term 
firm transmission and is rejected. Specifically, for service requests 
greater than a single day, week or month, Utilities For Improved 
Transition and Florida Power Corp's proposal decreases the period of 
time that such request is conditional; in other words, such request 
increases the unconditional reservation period, thus reducing the 
amount of longer-term transactions that the transmission provider can 
accommodate.

Sections 13.2 and 14.2

Rehearing Requests

    CCEM notes that short-term firm point-to-point transmission service 
customers that have already reserved service have a right to match any 
longer-term requests for service before being preempted pursuant to 
section 13.2. However, CCEM states that these tariff sections do not 
establish a deadline for when such right must be exercised. Because the 
tariff established a conditional reservation period for short-term firm 
transmission service (during which time longer-term firm transmission 
requests can preempt shorter-term conditional reservations) CCEM 
suggests that a shorter-term firm transmission customer should be 
allowed to exercise its right to match longer-term service requests up 
until the end of the conditional reservation period. CCEM requests a 
similar clarification for non-firm transmission service but does not 
propose specific modification.

Commission Conclusion

    While we agree with CCEM regarding the need to establish a deadline 
for exercising the right to match longer-term service requests for both 
short-term firm and non-firm transmission services, we will reject 
CCEM's proposed deadline for short-term firm transmission service. 
CCEM's proposed deadline would create market inefficiency by allowing 
the holder of the shorter-term firm transmission service an excessive 
amount of time to exercise its right to match the longer-term service. 
We feel that such a proposal could constitute a form of hoarding that 
would stifle the consummation of potential transactions and should not 
be allowed. CCEM's proposal would work to the detriment of any and all 
potential customer(s) requesting longer short-term firm transmission 
service. By allowing the original transmission customer to delay its 
response, the subsequent potential customer will be disadvantaged and 
may be required to make last minute alternative arrangements.
    We believe that an especially quick response time is necessary for 
hourly non-firm transmission service customers to match longer-term 
service requests. Hourly non-firm transmission customers must exercise 
their right to match longer-term service requests immediately upon 
notification by the transmission provider of a longer-term competing 
request for non-firm transmission service. For non-firm transmission 
service other than hourly transactions and short-term firm transmission 
service, we believe a customer should exercise its right to match 
longer-term service requests as soon as practicable. The prompt 
exercising of such right is particularly critical where scheduling 
deadlines for such transactions are imminent. However, even for 
transactions with longer lead-times before service is to commence, we 
believe a response deadline of no more than 24 hours from being 
informed by the transmission provider of a longer-term competing 
request for transmission service is appropriate. Accordingly, the 
customer will be required to respond to the transmission provider as 
soon as practicable after notification of a longer-term request for 
service, but no longer than 24 hours from being notified or earlier if 
required to comply with the scheduling requirements for such services 
in tariff section 13.8 and 14.6. Tariff sections 13.2 and 14.2 will be 
modified accordingly.

Section 13.5

Rehearing Requests

    Several utilities argue that section 13.5 is too broad because it 
also applies to costs that are included in rates on an embedded cost 
basis (which they claim can be evaluated when the transmission provider 
makes a rate filing).<SUP>420 They recommend that the Commission

[[Page 12356]]

modify the last sentence of the section as follows:

    \420\ E.g., Florida Power Corp, Utilities For Improved 
Transition, VEPCO.
---------------------------------------------------------------------------

    If redispatch costs or Network Upgrade costs are to be charged 
to the Transmission Customer on an incremental basis or costs 
relating to Direct Assignment Facilities that are to be charged to 
the Transmission Customer, the obligation of the customer to pay 
such costs shall be specified in the Service Agreement prior to the 
initiation of service.'' (Utilities For Improved Transition at 74-
75).

Commission Conclusion

    The Commission's intent in tariff section 13.5 was to require that 
any proposal to assess incremental charges to a customer must be 
specified in that customer's service agreement. Florida Power Corp and 
VEPCO correctly note that tariff section 13.5 inadvertently requires 
that any redispatch, network upgrade or direct assignment facilities, 
whether assessed on an incremental basis or included in embedded cost 
rates, must be specified in a customer's service agreement. To 
eliminate this unintended result, tariff section 13.5 is revised in 
relevant part as follows (new text underlined):

    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.

Section 13.6

Rehearing Requests

    CCEM asserts that the term ``Good Utility Practice'' should be 
deleted. CCEM claims that the inclusion of regional practices in Good 
Utility Practice makes the phrase vague and unpredictable. CCEM 
proposes that the Commission replace this phrase with a qualifier that 
pertains only to reliability and safety. According to PA Coops, equal 
priority places inordinate and unwarranted pressure on state siting and 
regulatory authorities to approve transmission projects required to 
provide service that may primarily benefit out of state parties. NYSEG 
argues that the Commission is not authorized to require curtailment of 
bundled retail service because it does not have jurisdiction over the 
rates, terms, and conditions of such service. It asserts that 
transactions subject to proportional curtailment should not include a 
transmitting utility's own use of its system to transmit its owned and 
purchased generation to native load customers as part of bundled retail 
service or services under rate schedules that are grandfathered. For 
transactions subject to proportional curtailment, NYSEG argues that 
allocation of curtailments will be comparable only if those multiple 
transactions being curtailed are of the same type of service and if 
each of the multiple transactions is for the same duration--these 
curtailments should be made on the same basis as required for non-firm 
PTP service. It asks the Commission to clarify that the curtailment 
requirements are not applicable to existing transmission contracts.

Commission Conclusion

    CCEM's concerns center on the inclusion of the phrase regional 
practices in the definition of Good Utility Practice in section 1.14 of 
the pro forma tariff. These concerns are answered in section 1.14 
above.
    PA Coops' argument that long-term firm point-to-point transmission 
customers should be curtailed before network service customers and 
native load ignores the fact that the transmission provider has an 
obligation under the pro forma tariff to expand or upgrade its 
transmission system in response to requests for such long-term point-
to-point transmission requests. In turn, such long-term firm point-to-
point transmission customers undertake an obligation to pay for any 
transmission facility additions necessary for the provision of service 
pursuant to the tariff. Comparability requires that all long-term firm 
transmission customer be treated on a not unduly discriminatory basis 
in terms of curtailment priority.
    Regarding NYSEG's arguments, the purpose of the curtailment 
provisions of the pro forma tariff is not to ``requir[e] curtailment of 
bundled retail service'' as NYSEG claims. Rather, the provision simply 
requires the transmission provider to curtail network and point-to-
point transmission services on a basis comparable to the curtailment of 
the transmission provider's service to its native load. Indeed, we have 
repeatedly indicated that we do not have jurisdiction over bundled 
retail sales.
    NYSEG's concerns regarding curtailment provisions in existing 
contracts are addressed above in Section IV.G.3.a. (Pro-rata 
Curtailment Provisions).

Section 13.7

Rehearing Requests

    Utilities For Improved Transition and Florida Power Corp state that 
section 13.7 of the pro forma tariff makes it uneconomic to engage in 
system sales transactions on a firm basis because it requires the 
transmission provider to impose a separate charge for transmission from 
each generating station. They ask that the Commission clarify that if 
there is a sale from multiple generators, a reservation of transmission 
from each point of receipt will be required only in the amount of the 
expected relative contribution of each generating station to the energy 
that is sold. If it is not so clarified, they argue that the Commission 
should make one of the following modifications: (1) permit the customer 
to designate more than one generating station as a single point of 
receipt if it provides likely loadings of the units to the transmission 
provider; (2) provide that where the customer takes service from a 
group of generating stations on an economic dispatch basis, the 
reserved capacity is the sum of the reservations at the points of 
delivery (must also provide likely loadings); or (3) add a new 
subsection to Article 31 that provides that a network integration 
transmission customer may also reserve service on a contract demand 
basis for periods as short as one day (but do not reduce the one-year 
minimum term for load-based network service).
    CSW Operating Companies asserts that the Commission should permit 
sales of power from multiple points of receipt, but such multiple 
generating units should be considered a single point of receipt. 
According to CSW Operating Companies, this provides maximum 
flexibility, lessens the need to establish secondary points of receipt, 
and is consistent with FMPA v. FPL, 74 FERC para. 61,006 at 61,014 
(1996). They ask that the Commission revise section 13.7(b) to provide: 
``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. Such multiple 
generating units shall be considered a single Point of Receipt when the 
underlying sale is to be made on a system basis and not from specific 
generating units.'' (CSW Operating Companies at 10-11). TAPS requests 
that the Commission clarify that a network customer may make system 
sales to third parties using the point-to-point provisions without 
designating each generating resource as a point of receipt. Moreover, 
it asks that if the Commission intends to depart from FMPA v. FPL, that 
transmission providers be held to the same burden.

Commission Conclusion

    Several utilities request rehearing on the tariff's requirement 
that sales of capacity and energy from multiple generating units must 
be designated as multiple points of receipt under point-to-point 
transmission service. These parties generally claim that this tariff 
requirement makes system sales

[[Page 12357]]

transactions uneconomical and is contrary to the Commission's 
determination in FMPA v. FPL, 74 FERC para. 61,006 at 61,014 (1996).
    As the Commission stated in the Final Rule:

all tariffs need not be ``cookie-cutter'' copies of the Final Rule 
tariff. Thus, under our new procedure, ultimately a tariff may go 
beyond the minimum elements in the Final Rule pro forma tariff or 
may account for regional, local, or system-specific factors. The 
tariffs that go into effect 60 days after publication of this Rule 
in the Federal Register will be identical to the Final Rule pro 
forma tariff; however, public utilities then will be free to file 
under section 205 to revise the tariffs, and customers will be free 
to pursue changes under section 206.<SUP>[421]

    \421\ FERC Stats. & Regs. at 31,770 n. 514; mimeo at 399 n. 514.
---------------------------------------------------------------------------

Utilities that advocate modifying the pro forma tariff to accommodate 
system sales are free to file their specific proposals with the 
Commission in a section 205 filing.<SUP>422 Such proposals are best 
reviewed on a case-specific basis where the type of system sales 
engaged in by the transmission provider or transmission customer can be 
identified and described in detail. In order to ensure comparability, 
any proposed tariff modifications submitted in order to facilitate 
system sales of the transmission provider must also apply for sales by 
transmission customers as well.
---------------------------------------------------------------------------

    \422\ See Commonwealth Edison Company and Commonwealth Edison 
Company of Indiana, Inc., 78 FERC para. 61,090 (January 31, 1997).
---------------------------------------------------------------------------

Section 13.7(b)

Rehearing Requests

    Blue Ridge argues that because units at the same geographic 
location can be connected to the system at different electrical 
locations, such as connections at different voltage levels (e.g., one 
unit connected at 500 kV and another unit connected at 230 kV), the 
Commission should replace the phrase ``at the same generating plant'' 
with ``at the same electrical location.'' (Blue Ridge at   23-24).

Commission Conclusion

    Blue Ridge's proposed change is unsupported. The rationale 
supporting the need for such change and its intended result is unclear 
and unexplained and appears to be unnecessary and overly restrictive. 
Many generating units at a single plant are connected to the 
transmission grid at multiple voltages. Therefore, taking Blue Ridge's 
proposal to its logical end, a customer could face an additional charge 
at a single unit for every voltage level connection. In contrast, the 
intent of section 13.7(b) of the pro forma tariff is to treat multiple 
units at a single plant as a single point of receipt to avoid charging 
a customer an unnecessary additional charge.

Section 13.8

Rehearing Requests

    CCEM asks the Commission to clarify that permissible scheduling 
changes extend to changes in the amount of power scheduled, the 
generation source, and delivery and receipt points. AMP-Ohio asserts 
that if the transmission provider can accommodate a change, the 
customer should be able to change its schedule less than 20 minutes 
before the hour or during the hour, and during an emergency or when the 
customer is attempting to remain within the 1.5% deviation band. It 
also asks the Commission to clarify that customers should be allowed to 
aggregate multiple points of delivery of less than a whole megawatt to 
be stated in whole megawatts (as is allowed for points of receipt). 
Otherwise, AMP-Ohio asserts, this would preclude small utilities from 
receiving service under a transmission provider's open access tariff.

Commission Conclusion

    We agree with CCEM that permissible scheduling changes include the 
amount of power scheduled (up to the amount of capacity reservation 
stated in the customer's service agreement). However, a proposed 
modification to the generation source or to receipt and delivery points 
on a firm basis under the pro forma tariff is not simply a scheduling 
change, as maintained by CCEM, but is a new request for service, as set 
forth in pro forma tariff section 22.2.
    AMP-Ohio's request regarding scheduling changes ignores the 
optional language in section 13.8 of the pro forma tariff, which 
permits a reasonable time limitation (other than the stated twenty 
minute deadline) that is ``generally accepted in the region and is 
consistently adhered to by the transmission provider.'' Accordingly, 
the pro forma tariff may be amended by the transmission provider to 
reflect the prevailing practice in the region.
    AMP-Ohio's request regarding scheduling changes to allow the 
customer to stay within the deviation band of 1.5 percent may not be 
feasible depending upon the ramping rates of the particular generating 
units and may allow erratic scheduling by customers that could 
interfere with the transmission provider's ability to provide load 
following service.
    AMP-Ohio's request for clarification that customers should be 
allowed to aggregate multiple points of delivery of less than a whole 
megawatt is unnecessary. Tariff section 17.2(viii) specifically allows 
customers to combine their requests for service for either points of 
receipt or points of delivery in order to satisfy the minimum 
transmission capacity requirement.

Section 14.2

Rehearing Requests

    Tallahassee asks the Commission to clarify that a non-firm customer 
facing possible interruption for economic reasons will be allowed to 
match the duration and price of the surviving transaction and that once 
a non-firm transaction begins, it will not be preempted without 
whatever notice is sufficient and appropriate in the region, but the 
time period should be no shorter than 1-2 hours.

Commission Conclusion

    The pro forma tariff does allow a customer to match a longer term 
reservation before being preempted. Moreover, non-firm transmission 
transactions, by definition, are interruptible for economic reasons (on 
a non-discriminatory basis) at any time. To the extent a prevailing 
regional practice exists regarding advance notice of interruption, the 
transmission provider may incorporate such a provision in its tariff.

Section 14.4

Rehearing Requests

    CCEM asks the Commission to clarify that a non-firm point-to-point 
service agreement is an Umbrella Agreement and a non-firm point-to-
point customer should be able to schedule a transaction at different 
primary and secondary receipt points and schedule changes in primary 
points with no filing requirement.

Commission Conclusion

    The form of service agreement for non-firm transmission service is 
a non-transaction specific umbrella service agreement (See Attachment B 
to the pro forma tariff). Therefore, the service agreement does not 
require a specification of receipt and delivery points for non-firm 
point-to-point transmission service. However, we note that changes to 
the receipt or delivery points for non-firm transmission service other 
than those points reserved by the transmission customer in its service 
request are not ``schedule'' changes as claimed by CCEM, but will 
require the

[[Page 12358]]

submission of a new application for service pursuant to Tariff Section 
18.

Section 14.6

Rehearing Requests

    CCEM asks the Commission to clarify that ``scheduling changes'' for 
non-firm transmission include changes in the amounts scheduled, changes 
in receipt and delivery points, or changes in primary points.

Commission Conclusion

    This issue is addressed in Section 13.8 above.

Sections 17, 18 and 29.2

Rehearing Requests

    The EPRI/NERC Working Group (formerly the ``What and How Industry 
Working Group'') identifies certain areas in the pro forma tariff 
``where the perceived scope of OASIS has grown beyond that which is 
feasible in Phase 1'' of OASIS. (EPRI/NERC Working Group at 2). EPRI/
NERC Working Group references various information required in the 
application process under the pro forma tariff that is required to be 
submitted via OASIS to the transmission provider. EPRI/NERC Working 
Group explains that a substantial amount of information required under 
the pro forma tariff ``cannot be provided via the OASIS in Phase 1'' 
(e.g., service agreements, requests for (A) non-firm point-to-point 
transmission service in the next hour, (B) multiple receipt and 
delivery points, (C) addition of new network loads or resources, 
loadflow and stability data).
    The EPRI/NERC Working Group also claims that tariff section 17.1 
creates confusion as it first requires that ``[a] request for Firm 
Point-To-Point Transmission Service * * * must contain a written 
Application * * *'' to the transmission provider, but then requires 
``[a]ll Firm Point-To-Point Transmission Service requests should be 
submitted by entering the information listed below on the Transmission 
Provider's OASIS.'' (Emphasis added). The EPRI/NERC Working Group 
asserts that the above language confuses the process of an 
``application for service agreement'' versus the process of ``a request 
for transmission service'' by a customer who already has a service 
agreement.

Commission Conclusion

    The Commission recognizes that implementation of the OASIS is being 
accomplished in phases. In recognition of this fact, section 17.1 of 
the pro forma tariff provides:

    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.

Moreover, we clarify that if Phase 1 of OASIS implementation does not 
support the submission of certain information over the OASIS, such 
information may be submitted by telephone or telefax (facsimile), as 
provided in the pro forma tariff, and promptly (within one hour) posted 
on OASIS by the Transmission Provider.<SUP>423
---------------------------------------------------------------------------

    \423\ On December 27, 1996, the Commission issued an order that 
found that
    During Phase 1, a request for transmission service made after 
2:00 p.m. of the day preceding the commencement of such service, 
will be ``made on the OASIS'' if it is made directly on the OASIS, 
or, if it is made by facsimile or telephone and promptly (within one 
hour) posted on the OASIS by the Transmission Provider.
    77 FERC para. 61,335 (1996).
---------------------------------------------------------------------------

    Concerning the EPRI/NERC Working Group's apparent confusion 
regarding service application processes, we previously explained in 
Section IV.G.6 that the Commission is modifying the application process 
for firm point-to-point transmission transaction of less than one year 
(short-term firm transactions). The Commission will permit an 
``umbrella service agreement'' approach where all of a customer's 
short-term firm transactions can be arranged under a single non-
transaction specific umbrella service agreement rather than requiring a 
new service agreement for each short-term firm transaction. In 
contrast, service agreements for firm point-to-point transmission 
transactions of one year or more (long-term firm transactions) are 
transaction specific and require a separate service agreement for each 
transaction.

Section 17.1

Rehearing Requests

    CCEM states that the 60 days in advance to request service should 
be shortened to 6 days. For service shorter than one year, it argues 
that the procedures should not be left to negotiation with a 
monopolist. For service greater than one month but less than one year, 
it asserts that a request should be submitted 3 days in advance; for 
weekly service, schedules should be submitted by some specific hour the 
day before service is to commence; and for hourly or daily service, 
schedules should be submitted no later than 20 minutes in advance.

Commission Conclusion

    CCEM has provided no support for its proposal to shorten the lead 
time for requests for firm service from sixty days to six days. Sixty 
days in advance of the commencement of long-term (greater than one 
year) firm service is not an unreasonable time period. It provides 
transmission providers time to conduct security analyses, as well as 
perform system impact studies and facility studies that may be 
necessary. Accordingly, CCEM's request is denied.

Section 17.2

Rehearing Requests

    CCEM argues that information concerning the location of the 
generating facility and the load ultimately served is not required in 
connection with a good faith request under the Policy Statement 
Regarding Good Faith Request for Transmission Services and should not 
be required in a Completed Application. However, if it is required, 
CCEM argues that it should remain confidential and not be disclosed. It 
further asks the Commission to clarify that a point-to-point customer 
can designate all receipt and delivery points in order to obtain 
umbrella-type service and can schedule receipt and delivery points as 
primary or secondary and can change primary points by filing another 
schedule.

Commission Conclusion

    We will deny CCEM's proposed changes in part as unnecessary. The 
locations of generating facilities and loads are needed by the 
transmission provider to allow it to analyze whether the requested 
transmission service can be accommodated over the existing transmission 
system, as well as to plan upgrades and transmission facility 
additions.<SUP>424
---------------------------------------------------------------------------

    \424\ We further note that CCEM's reference to the Commission's 
Policy Statement Regarding Good Faith Request for Transmission 
Services does not support its position. As we there stated,
    [a] good faith request for transmission service should also 
contain a specific, technical description of the requested services 
in sufficient detail to permit the transmitting utility to model the 
additional services or its transmission system.
    FERC Stats. & Regs. para. 30,975 at 30,863.
---------------------------------------------------------------------------

    Tariff section 17.2 already requires that ``the transmission 
provider shall treat this [confidential] information consistent with 
the standards of conduct contained in Part 37 of the Commission's 
regulations.''
    With respect to CCEM's request to permit umbrella-type service, we 
note that we have adopted an umbrella-type service agreement approach 
for short-term firm transmission service, as

[[Page 12359]]

discussed in Section IV.G.6 (Umbrella Service Agreements).

Section 17.3

Rehearing Requests

    CCEM asserts that a customer determined to be creditworthy should 
not have to submit a deposit for firm point-to-point transmission 
service. CCEM would limit this section to those customers found not to 
be creditworthy and asks the Commission to clarify that only the costs 
of system impact studies or facilities studies can be deducted from the 
deposit.

Commission Conclusion

    Section 17.3 reflects a standard requirement in many existing 
tariffs and other agreements on file with this Commission. CCEM 
provides no compelling reason to revise this tariff provision.
    We also deny CCEM's request regarding deductions from the deposit. 
We will not preclude a utility from demonstrating that it incurs costs 
other than system impact studies or facilities studies in processing a 
service application and arguing that these costs should be deducted 
from a deposit.

Section 17.4

Rehearing Requests

    CCEM argues that a deficiency determination should be made in, at 
most, one day.

Commission Conclusion

    CCEM provides no compelling reason to revise this tariff provision. 
CCEM's argument also ignores the fact that certain applications involve 
more complex unique transactions and associated arrangements which may 
require more time to review than other more standard applications. 
CCEM's apparent concern regarding deficient applications should be 
mitigated by the pro forma tariff requirement that the transmission 
provider must attempt to remedy minor deficiencies in the application 
informally with the transmission customer.

Section 17.5

Rehearing Requests

    CCEM asserts that a transmission provider should respond to a 
completed application for firm transmission service within 10 minutes 
for hourly service, 10 minutes for daily service, 4 hours for weekly 
service, 1 day for monthly service, 2 days for service longer than one 
month but less than one year, and 5 days for service one year or 
longer.

Commission Conclusion

    Section 17.5 requires the transmission provider to notify the 
eligible customer as soon as practicable, but no later than 30 days 
after receipt of a completed application if it can provide the service 
or if a system impact study will be required. We do not believe that 
further specificity in establishing deadlines for each type of service 
and duration of service is necessary. However, we are clarifying 
section 17.5 to require that all responses be made on a non-
discriminatory basis. If CCEM believes the transmission provider is 
engaging in discriminatory behavior by delaying responses to service 
requests (or by responding to service requests by its wholesale 
merchant function more quickly than it responds to service requests by 
unaffiliated customers), it can file a section 206 complaint with the 
Commission.

Section 17.7

Rehearing Requests

    Several utilities ask the Commission to clarify that, if 
transmission facilities have been constructed to accommodate a request 
for transmission service, delays by the customer in commencing service 
should be prohibited or the customer should pay the full carrying 
charges on the facilities during the period of delay (less any revenues 
received).<SUP>425 Similarly, EEI and Southern argue that if new 
facilities are constructed, but the customer postpones service by 
paying a reservation fee, fairness requires that the customer bear its 
cost responsibility for the new construction at the time the facilities 
are ready to be used.
---------------------------------------------------------------------------

    \425\ E.g., Utilities for Improved Transition, Florida Power 
Corp, VEPCO.
---------------------------------------------------------------------------

Commission Conclusion

    Because different factual circumstances could exist that may lead 
to alternative solutions to the problem, we will not adopt a generic 
resolution. Rather, the Commission believes it appropriate to allow 
each utility to propose solutions in subsequent section 205 filings 
with the Commission.

Section 19

Rehearing Requests

    VA Com asks the Commission to clarify that determining the 
necessity of a transmission facility upgrade or addition remains a 
state prerogative. It asserts that native load customers may face 
reduced reliability, or may incur costs associated with premature 
additions, if calculations of ATC are incorrect. In addition, it 
asserts that generating facilities can also be used to relieve regional 
capacity constraints--``For example, a current proposal by Virginia 
Electric and Power Company (``Virginia Power'') seeks the Virginia 
Commission's approval of a major new transmission line. Virginia Power 
alleges that the line is needed since it would increase the 
availability of emergency off-system supplies and allow it to lower its 
capacity reserve requirements. If the Virginia Commission were to 
approve the line, it is conceivable that FERC could direct Virginia 
Power to use this additional interchange capability to facilitate 
wholesale wheeling transactions. In such an event, native load 
customers may be adversely affected since the utility would be forced 
to suffer diminished reliability or build additional generation or 
transmission facilities.'' (VA Com at 10-12). CCEM asks the Commission 
to require studies for short-term firm point-to-point service or 
requests for capacity that are posted on the OASIS.

Commission Conclusion

    In the Final Rule, the Commission explicitly stated that

public utilities may reserve existing transmission capacity needed 
for native load growth and network transmission customer load growth 
reasonably forecasted within the utility's current planning horizon. 
However, any capacity that a public utility reserves for future 
growth, but is not currently needed, must be posted on the OASIS and 
made available to others through the capacity reassignment 
requirements, until such time as it is actually needed and 
used.<SUP>426

    \426\ FERC Stats. & Regs. at 31,694; mimeo at 172.
---------------------------------------------------------------------------

This ability to reserve capacity to meet the reliability needs of 
native load would apply equally to transmission built in the future.
    VA Com requested clarification of the intended treatment by the 
Commission in the ATC calculation of a transmission line built in lieu 
of generation for purposes of lowering reserve requirements for native 
load. If it seeks to withhold capacity in response to a request for 
service by an eligible customer, the transmission provider will have 
the burden of proof to demonstrate that any reserved capacity is needed 
for meeting native load and network customers' load growth or for 
purposes of meeting a reserve requirement level that is reasonable.
    CCEM's request is unnecessary because system impact studies and 
facilities studies are required pursuant to tariff section 19 for both 
long-term and short-term firm point-to-point transmission service.

[[Page 12360]]

Sections 19.2 and 32.2

Rehearing Requests

    Utilities For Improved Transition and VEPCO ask the Commission to 
modify these sections to require that a system impact study agreement 
specify the estimated charge instead of the maximum charge so that the 
transmission provider may collect all prudently incurred study costs.

Commission Conclusion

    Utilities For Improved Transition and VEPCO correctly note that the 
use of the phrase ``maximum'' in the language of tariff sections 19.2 
and 32.2 may prevent a utility from collecting the full costs of 
conducting a system impact study despite acting in a prudent manner. 
Accordingly, the relevant portion of these sections are modified as 
shown below to eliminate this potential inequity (deleted text in 
brackets):

    (i) The System Impact Study Agreement will clearly specify [the 
maximum charge, based on] 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.

Sections 19.3 and 19.4

Rehearing Requests

    TAPS asserts that the 15-day periods for customers to execute a 
service agreement after completion of a system impact study are too 
short and should be lengthened to 30 days or the transmission provider 
should be allowed to provide an extension for cause (with public 
notice) while the customer is pursuing an agreement in good faith.

Commission Conclusion

    TAPS' proposed changes are not necessary because the eligible 
customer is provided a sufficient response time considering the 
situation to which the eligible customer is responding. Specifically, 
the 15-day period in section 19.3 refers to the situation where the 
transmission provider has conducted a system impact study and concluded 
that the requested service can be provided without the need to modify 
its transmission system. TAPS provides no reason why the eligible 
customer requesting the service should not be prepared to immediately 
accept the offer to provide service at the transmission provider's 
standard rate (without the need for upgrades, the eligible customer 
would not be assessed incremental transmission charges).
    Similarly, the 15-day period in section 19.4 refers to the time in 
which the eligible customer has to execute a facilities study agreement 
in which it agrees to pay the transmission provider for the costs of 
conducting a facilities study. In contrast, when the facilities study 
is completed and the eligible customer is provided with a good faith 
estimate of any direct assignment facilities and/or share of any 
network upgrades, section 19.4 provides the eligible customer with 30 
days to respond.

Section 22.1(d)

Rehearing Requests

    Utilities For Improved Transition and Florida Power Corp ask the 
Commission to modify this section to require that a request for 
modification of service on a non-firm basis be made by submitting a 
modification to the original application with an OASIS posting. 
Otherwise, they assert, this section implies that such modifications 
would occur without using the transmission provider's OASIS.

Commission Conclusion

    Utilities For Improved Transition and Florida Power Corp 
misinterpret this section of the tariff. The Commission's intention is 
simply to clarify that the customer's request to modify its firm 
transmission service to receive service over secondary receipt and 
delivery points on a non-firm basis would not require a separate 
application for non-firm transmission service. The concerns expressed 
with respect to posting on the OASIS are addressed in Order No. 889-A.

Section 23.1

Rehearing Requests

    CCEM asserts that the Commission sHhould specify the filings 
necessary for assignment of service referenced in this section or 
delete the clause. In addition, CCEM asks the Commission to clarify 
that the identical services will be provided at no additional cost to 
the assignee or the reseller.

Commission Conclusion

    The pro forma tariff is a tariff of general applicability. For 
administrative reasons, the listing of every conceivable situation in 
which an assignment or transfer of service from one entity to another 
may require a separate filing is not feasible. For example, if the 
Commission lists only a single situation that requires a separate 
filing and subsequently determines another situation would also require 
a filing, all of the pro forma tariffs on file with the Commission 
would need to be revised to reflect the change.
    CCEM's request that the Commission clarify that reassigned services 
will be provided at no extra cost is also denied. CCEM ignores the fact 
that nothing in the pro forma tariff prevents the transmission provider 
from seeking a change in rates pursuant to a section 205 filing whether 
such filing relates to a general increase in rates to all transmission 
customers or to additional costs the transmission provider asserts it 
incurs due to providing service to an assignee. As always, the 
transmission provider bears the burden of proof of demonstrating that 
its proposal is just and reasonable.

Section 23.2

Rehearing Requests

    CCEM asks the Commission whether an assignee can change primary 
points if there is only a partial assignment.

Commission Conclusion

    Whether the assignment is full or partial is immaterial. If an 
assignee wishes to change its receipt or delivery points on a firm 
basis (full or partial), the request will be treated as a new request 
for service as required under tariff sections 22.1 and 23.1. However, 
if an assignee wishes to change receipt or delivery points on a non-
firm (full or partial) basis, such change can be accomplished without 
the need for a new service agreement as provided in pro forma tariff 
section 22.1.

Sections 25 and 34

Rehearing Requests

    VT DPS asks the Commission to revise these sections to state that 
``all firm customers should share in non-firm revenues'' consistent 
with the language of the preamble.

Commission Conclusion

    VT DPS' request is denied. The Commission did not intend to mandate 
the rate methodology used to reflect any cost reductions that may be 
associated with the provision of non-firm transmission service. While 
the Commission would generally expect all firm customers to share in 
non-firm revenues, the use of revenue credits is not the only 
acceptable method of reflecting non-firm system usage. The transmission 
provider's method of reflecting revenues from non-firm service should 
be addressed on a case-by-case basis.

Section 29.1

Rehearing Requests

    TAPS contends that, to avoid improper use of operating agreements 
by transmission providers, the

[[Page 12361]]

Commission should either permit network operating agreements to be 
filed in unexecuted form or include a network operating agreement as 
part of the pro forma tariff.

Commission Conclusion

    The network operating agreement is expected to be a highly detailed 
agreement between the transmission provider and network customer that 
establishes the integration of the network customer within the 
transmission provider's transmission system. Due to the unique 
characteristics of network customers' systems and the level of 
customer-specific information and arrangements required under a network 
operating agreement, it is likely that each network operating agreement 
will be different for each customer. Accordingly, the Commission does 
not believe it appropriate to mandate a particular form of network 
operating agreement for inclusion in the pro forma tariff. However, if 
a transmission provider wishes to include a generic form of network 
operating agreement in its pro forma tariff (to be modified as required 
and as mutually agreed to on a customer-specific basis), it may propose 
to do so in a section 205 filing or it may file an unexecuted network 
operating agreement in a section 205 filing.
    To the extent a customer believes a transmission provider is 
engaging in unduly discriminatory practices via the network operating 
agreement, the customer may file a section 206 complaint with the 
Commission.

Section 29.4

Rehearing Requests

    TDU Systems asserts that this section does not identify who should 
determine what facilities are ``necessary to reliably deliver capacity 
and energy. * * *'' It asks the Commission to clarify that this is 
solely the responsibility of the transmission customer.

Commission Conclusion

    TDU Systems' argument ignores tariff section 35.1, which specifies:

[t]he Network Customer shall plan, construct, operate and maintain 
its facilities in accordance with Good Utility Practice and in 
conformance with the Network Operating Agreement. (emphasis added)

Accordingly, the determination of what network customer facilities are 
``necessary to reliably deliver capacity and energy * * *'' is to be 
agreed upon by both the transmission provider and network customer and 
specified in the network operating agreement. To the extent the parties 
do not agree, the transmission provider will file an unexecuted network 
operating agreement with the Commission and we will resolve the 
dispute.

Section 30.1

Rehearing Requests

    VT DPS argues that, consistent with section 30.7, section 30.1 
should not require that a network resource be available on a strictly 
non-interruptible basis.

Commission Conclusion

    VT DPS' request is denied. The Commission believes that a network 
customer should only be allowed to designate non-interruptible network 
resources. To allow otherwise would interfere with the planning process 
as well as the day-to-day operation of the transmission system to 
integrate resources with customer's loads (e.g., the transmission 
provider will be unable to plan for what generation resource will be 
available to meet a customer's load in the event its designated 
resource is subject to interruption). Similarly, for operational 
purposes on a day-to-day basis, an interruption of a network customer's 
designated resource could cause a transmission constraint.<SUP>427 
Because constraints affecting reliability may lead to curtailment or 
redispatch of all network resources, other network customers would be 
affected by such interruptions on a load-ratio basis. However, to the 
extent a network customer wishes to use an interruptible generation 
source, it can still use this generation source on an as-available 
basis to import energy to serve its load pursuant to pro forma tariff 
section 28.4.
---------------------------------------------------------------------------

    \427\ While firm resources can also go off line, the probability 
of this happening is less than that for interruptible resources.
---------------------------------------------------------------------------

Section 30.4

Rehearing Requests

    PA Coops ask the Commission to modify this section ``to permit the 
Network Resources to be operated at outputs that exceed the Network 
Customer's designated Network Load plus losses when the Network 
Resource's output is being sold to a third party or the Network 
Resource is called upon to be operated by the Network Customer's power 
pool, ISO or control area operator.'' (PA Coops at 8-9). Similarly, 
Santa Clara and Redding ask the Commission to modify the last sentence 
to state: ``* * * exceeds its designated Network Load, plus non-firm 
sales delivered under Part II, plus losses'' so that network resources 
will not remain idle when they could otherwise generate non-firm power 
and energy for sale at competitive prices.
    In addition, TDU Systems argues that the arbitrary limits on the 
ability of network customers to operate Network Resources prevents 
economic dispatch or the use of resources to meet load requirements and 
limits the ability to schedule the output of Network Resources between 
and among control areas, effectively preventing the network customer 
from operating an integrated system.<SUP>428 TDU Systems asserts that 
the Commission should not presume that a network customer's economic 
dispatch will burden a transmission provider, but should require a 
transmission provider to demonstrate that such a burden will occur. 
TAPS asks the Commission to clarify this section so as to bar not the 
operation of network resources in excess of network load, but rather 
the usage of network service in connection with operation of such 
resources in excess of network load. TAPS adds that section 30.4 is 
contrary to FMPA v. FPL, 74 FERC at 61,014-15. AEC & SMEPA argues that 
the Commission should provide the necessary latitude for such resources 
to be used across multiple control areas to service the total load of 
transmission users.
---------------------------------------------------------------------------

    \428\ See also NRECA.
---------------------------------------------------------------------------

Commission Conclusion

    Preliminarily, TDU Systems and others' argument that a designated 
network resource must consist of the entirety of a generating unit is 
mistaken, as we explained in sections 1.22 and 1.25 above. The 
Commission's intent in requiring that the output of network resources 
not exceed network load plus losses is to prevent designated network 
resources from being used to make firm sales to third parties. This is 
consistent with the pro forma tariff's requirement in sections 1.25 and 
30.1 that:

    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.

    Absent a requirement that network resources always be available to 
meet a customer's network loads, reliability of service to the network 
customer as well as to native load and other network customers could be 
affected, as we describe in detail in section 30.1 above. If a network 
customer desires to enter into a firm sale from its designated network 
resources or use such network resources for meeting reserve 
requirements, it must eliminate the appropriate resources or portions 
thereof from its designated network

[[Page 12362]]

resources pursuant to pro forma tariff section 30.
    Santa Clara, Redding and others contend that this limitation 
improperly restricts the use of network resources for non-firm sales. 
It was not the Commission's intent to prohibit the network customer 
from engaging in non-firm sales from idle designated network resources. 
We find that the non-firm operation of network resources will not 
affect the availability of such resources on a firm basis because such 
non-firm uses are subject to interruption. Accordingly, the 
Commission's concerns regarding the reliable provision of network 
service are satisfied.
    Furthermore, as noted by Pennsylvania Coops, emergencies could 
arise in which the transmission provider may request that a network 
customer alter the operation of its network resources in response to a 
contingency, which action could result in a violation of the limitation 
in section 30.4. Therefore, the Commission believes an exception to the 
network resources output limitation is also appropriate for such 
emergency situations. Accordingly, tariff section 30.4 is revised, in 
relevant part, consistent with the above findings, as shown below 
(emphasis added):

    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 its Transmission 
System.

    The remaining concerns expressed by TDU Systems with respect to the 
economical operation of a network customer's loads and resources 
located in multiple control areas are addressed above in Section 
IV.G.1.b. (Network and Point-to-Point Customers' Uses of the System 
(so-called ``Headroom'')).

Section 30.6

Rehearing Requests

    CSW Operating Companies asks the Commission to clarify that a 
customer has the obligation to replace the loss of a resource that is 
not physically interconnected with the transmission provider's 
transmission system within the time that is customary in the region or 
be subject to curtailment and suggests language to be included as 
section 33.8. CSW Operating Companies indicates that it intends to 
include a provision addressing this issue in the form of a network 
operating agreement included in the individual companies' Final Rule 
compliance tariffs.

Commission Conclusion

    The Commission agrees with CSW Operating Companies that the 
appropriate place to address detailed operational requirements such as 
this is the Network Operating Agreement. If disputes arise, they can be 
addressed on a case-by-case basis.

Section 30.7

Rehearing Requests

    Wisconsin Municipals asks the Commission to clarify that, for 
purposes of comparability between network and point-to-point customers, 
a customer may not reserve capacity for firm point-to-point 
transmission service until the customer can show that it owns or has 
committed to purchase generation under an executed contract that it 
intends to use over the reserved transmission contract path. Wisconsin 
Municipals claims that without the requirement to demonstrate ownership 
or contractual rights to the output of a generation resource, the 
point-to-point customers will have the advantage over network customers 
of being able to reserve transmission service over facilities with 
limited available transmission capacity earlier than network customers. 
Wisconsin Municipals also argues, in essence, that a single or a few 
point-to-point customers would be able to engage in hoarding of 
transmission capacity by reserving all available transmission capacity 
over certain transmission facilities.

Commission Conclusion

    The arguments presented by Wisconsin Municipals in support of its 
proposal are misplaced. Wisconsin Municipals' assertion that point-to-
point customers would be able to reserve transmission service over 
facilities with limited available transmission capacity earlier than 
network customers overlooks the fact that the Final Rule allows 
transmission providers to reserve existing transmission capacity needed 
for native load growth and network transmission customer load growth 
reasonably forecasted within the transmission provider's current 
planning horizon.<SUP>429 Wisconsin Municipals' concerns regarding 
hoarding of transmission capacity are answered in Section IV.C.6. 
(Capacity Reassignment). Finally, Wisconsin Municipals' argument that 
comparability requires that both network and point-to-point customers 
be required to demonstrate ownership or contractual rights to the 
output of a generation resource is not persuasive. Network and firm 
point-to-point transmission service are different services. Firm point-
to-point transmission service is available for periods as short as one 
day, whereas network service is designed to accommodate a longer term 
of service with a minimum term of service of one year. The requirement 
to demonstrate ownership or contractual rights to generation for 
network service is necessary because the transmission provider must be 
able to serve the network load from any of the designated resources. In 
contrast, point-to-point service is a capacity reservation service 
between specified points of receipt and points of delivery. 
Accordingly, this network requirement does not need to be extended to 
firm point-to-point service under the guise of comparability.
---------------------------------------------------------------------------

    \429\ FERC Stats. & Regs. at 31,694; mimeo at 172.
---------------------------------------------------------------------------

Section 31.2

Rehearing Requests

    TDU Systems asks the Commission to clarify that an application for 
new network load for an existing network customer need only address the 
additional network service needed to serve the new Network Load and 
does not in any way implicate the existing network service for which 
the network customer has already contracted.

Commission Conclusion

    No clarification is necessary. Tariff section 31.2 explicitly 
states in relevant part:

    A designation of new Network Load must be made through a 
modification of service pursuant to a new Application. (Emphasis 
added)

Section 32.3

Rehearing Requests

    TDU Systems asserts that this section requires too short a time for 
customers to evaluate a system impact study. It argues that, at a 
minimum, customers should have 60 days to evaluate a study and, in the 
event of a dispute, the application should remain viable until the 
dispute is resolved (also argues that the time periods set forth in 
sections 19.1, 19.4, 32.1, 32.3 and 32.4 are too short).

Commission Conclusion

    TDU Systems' proposed changes are not necessary as the pro forma 
tariff provides an eligible customer sufficient time to respond to a 
system impact

[[Page 12363]]

study. Specifically, the 15-day period in section 32.3 refers to a 
situation where the transmission provider has conducted a system impact 
study and concluded that the requested service can be provided without 
the need to modify its transmission system. TDU Systems provides no 
reason why the eligible customer should not be prepared to immediately 
accept the offer of providing service at the transmission provider's 
standard rate (without the need for upgrades, the eligible customer 
would not be assessed incremental transmission charges).
    Similarly, the 15 day period in sections 19.1, 19.4, 32.1 and 32.4 
refer to the time in which the eligible customer has to agree to 
execute an agreement to pay the transmission provider for costs of 
conducting studies (a system impact study in sections 19.1 and 32.1 and 
a facilities study in sections 19.4 and 32.4). TDU Systems provides no 
reason why it should not be prepared to accept or reject the relatively 
minor costs of further studies to determine whether its requested 
transmission service can be accommodated by the transmission provider.
    In contrast, when the facilities study is completed and the 
eligible customer is provided with a good faith estimate of any direct 
assignment facilities and/or share of any network upgrades, the 
eligible customer is given 30 days to respond, which is more than a 
sufficient time.

Sections 33.2 and 34.4

Rehearing Requests

    TAPS asserts that the Commission cannot shunt aside the need for 
ongoing revenue crediting to reduce transmission charges as a rate 
issue, while allowing monthly redispatch costs to be collected monthly 
in charges under the tariff. It contends that the Commission must 
require revenues to be shared on an ongoing, load-ratio basis.

Commission Conclusion

    As discussed above, redispatch of all Network Resources and the 
transmission provider's own resources is only to be performed to 
maintain the reliability of the transmission system, not for economic 
reasons. As a result, the frequency of redispatch charges being 
assessed to network customers is expected to be infrequent. In 
addition, the Commission is according substantial flexibility to public 
utilities to propose appropriate pricing terms in their compliance 
tariff, which includes the treatment of revenue credits. As mentioned 
above, there are several methods that utilities can use to properly 
reflect a benefit from non-firm transmission service to firm 
transmission customers. We do not believe it appropriate to mandate a 
specific method, such as automatic monthly flow through of revenue 
credits, at this time. However, TAPS may pursue this issue when 
utilities file their compliance rates or subsequent 205 rate filings.

Section 34.3

Rehearing Requests

    Several utilities assert that because the monthly transmission 
system load is composed in part of the contract demands of all firm 
point-to-point transmission customers and under the Rule the charge for 
firm point-to-point service may be derived by dividing the transmission 
cost of service by the sum of the transmission provider's 12 monthly 
peak firm transmission loads, the transmission provider is prevented 
from recovering its entire cost of service.\430\
---------------------------------------------------------------------------

    \430\ E.g., Utilities For Improved Transition, Florida Power 
Corp, VEPCO (asserts that rates for firm point-to-point service 
should be developed in the same way).
---------------------------------------------------------------------------

    Maine Public Service states that parties should be allowed to argue 
on a case-by-case basis that firm transmission revenues should be 
credited instead of including the demands in the denominator (it 
indicates that this issue is pending in Docket No. ER95-836). It 
asserts that the revenue credit method would prevent transmission 
providers that offered discounts from unjustly being penalized for that 
decision and is the only method that permits utilities to have an 
opportunity to recover their costs. It adds that the Commission 
established procedures to keep gas pipelines whole in this same 
situation.

Commission Conclusion

    While the Commission established one method of calculating load 
ratios and allocating costs in Order No. 888,\431\ utilities are free 
to propose alternative pricing methodologies in a section 205 filing 
consistent with the Commission's Transmission Pricing Policy 
Statement.\432\ We note, however, such utilities will have the burden 
of demonstrating that these methods would not result in over-
collections of their revenue requirement.
---------------------------------------------------------------------------

    \431\ FERC Stats. & Regs. at 31,738; mimeo at 304.
    \432\ See FERC Stats. & Regs. at 31,768-70; mimeo at 394-99.
---------------------------------------------------------------------------

Section 34.4

Rehearing Requests

    TDU Systems asks the Commission to clarify, as a matter of 
comparability, that any mechanism proposed by a transmission provider 
to collect charges based on opportunity costs associated with 
redispatch must provide for the collection of other customers' like 
costs and payments to those customers.

Commission Conclusion

    This issue is addressed in Section IV.G.1.e. (Opportunity Cost 
Pricing).

Schedules 7 and 8

Rehearing Requests

    TAPS asks the Commission to clarify that these schedules do not 
approve ``heightened'' charges for short-term services.

Commission Conclusion

    The Commission did not specify transmission rates for any tariff 
services in Order No. 888. The rates for long-term firm transmission, 
short-term firm transmission and non-firm transmission services are to 
be proposed by the transmission provider, as listed on Tariff schedules 
7 and 8, and filed with the Commission. TAPS' argument regarding 
``heightened'' charges for these services is therefore premature. TAPS 
is free to raise this concern at such time as utilities file their 
proposed transmission rates.

Attachment G

Rehearing Requests

    Santa Clara and Redding ask the Commission to modify Attachment G 
so that, where interconnection/operational standards are in place and 
working effectively, additional standards are not imposed simply as a 
result of switching to the pro forma tariff from its current 
interconnection service.

Commission Conclusion

    The pro forma tariff does not specifically require that the network 
operating agreement between the transmission provider and network 
customer must be a new agreement. However, the network operating 
agreement is expected to be a highly detailed agreement between the 
transmission provider and network customer establishing the integration 
of the network customer within the transmission provider's transmission 
system. Existing agreements between the customer and transmission 
provider may not provide all of the information required or make all of 
the technical arrangements required under the pro

[[Page 12364]]

forma tariff (e.g., redispatch and ancillary services information and 
arrangements.) Nevertheless, to the extent the transmission customer is 
currently receiving network integration transmission service or similar 
service and its present interconnection agreement fully comports with 
the requirements of the terms and conditions of the tariff including 
the informational requirements specified in tariff sections 33 and 35, 
then the present interconnection/operations agreement can be 
substituted for a network operating agreement or modified 
appropriately.
9. Miscellaneous Tariff Administrative Changes
    Due to administrative oversight, certain tariff sections require 
minor corrections or modifications. Because of the administrative 
nature of these changes, we believe that no further discussion is 
needed.
Section 12.1  Internal Dispute Resolution Procedures
--Changes ``Transmission Service'' to ``transmission service''
Section 13.6  Curtailment of Firm Transmission Service
--Changes the description regarding curtailment of multiple 
transactions to:

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.
10. Pro Forma Tariff Compliance Filings
    Absent a waiver, all public utilities must submit, no later than 
July 14, 1997, a compliance filing that reflects the tariff changes set 
forth in this order on rehearing.\433\
---------------------------------------------------------------------------

    \433\ To the extent a public utility has been granted a waiver 
of the Order No. 888 tariff filing requirements (or a non-public 
utility for reciprocity purposes), it need not submit a request for 
a separate waiver of the requirements of this order on rehearing.
---------------------------------------------------------------------------

    A conforming pro forma tariff, containing all the revisions and 
clarifications contained in this order on rehearing, is attached as 
Appendix B. In addition, an electronic version of the conforming pro 
forma tariff will be made available on the Commission's electronic 
bulletin board service (Commission Issuance Posting System (CIPS)) in 
redline/strikeout form in WordPerfect 5.1 format.

H. Implementation

    In the Final Rule, the Commission set forth the details of the 
implementation procedures and included special implementation 
requirements for coordination arrangements (power pools, public utility 
holding companies, and bilateral coordination arrangements).\434\
---------------------------------------------------------------------------

    \434\ FERC Stats. & Regs. at 31,768-70; mimeo at 393-400.
---------------------------------------------------------------------------

The Revised Procedures

    The Commission adopted slightly different implementation procedures 
for Group 1 public utilities (tendered for filing open access tariffs 
before the date of issuance of the Rule) and for Group 2 public 
utilities (did not tender for filing open access tariffs before the 
date of issuance of the Rule).
1. Group 1 Public Utilities
    In the Final Rule, the Commission required Group 1 public 
utilities, within 60 days following publication of the Final Rule in 
the Federal Register, to make section 206 compliance filings that 
contain the non-rate terms and conditions set forth in the Final Rule 
pro forma tariff and identify any terms and conditions that reflect 
regional practices, as discussed below.\435\
---------------------------------------------------------------------------

    \435\ FERC Stats. & Regs. at 31,768-69; mimeo at 394-96.
---------------------------------------------------------------------------

    As to rates, the Commission noted that a transmission tariff rate 
is already in effect for all Group 1 public utilities, except for the 
few with recently-tendered applications that have not yet been accepted 
for filing.
    The Commission noted, however, that if a Group 1 public utility 
determined that certain rate changes are necessitated by the revised 
non-rate terms and conditions, it may file a new rate proposal under 
FPA section 205. The Commission indicated that such filings must be 
``conforming'' \436\ under the Transmission Pricing Policy Statement 
and must be made no later than 60 days after publication of the Final 
Rule in the Federal Register and intervenors may raise any concerns 
with the filings within 15 days after such filings. \437\ The 
Commission imposed a blanket suspension for any filings by Group 1 
public utilities proposing rate changes necessitated by the new non-
rate terms and conditions. The Commission further indicated that these 
rates will go into effect, subject to refund, 60 days after publication 
of this Rule in the Federal Register (the same day on which the non-
rate terms and conditions of the Final Rule pro forma tariff go into 
effect).
---------------------------------------------------------------------------

    \436\ As described in the Transmission Pricing Policy Statement, 
a ``conforming'' proposal is one that meets the traditional revenue 
requirement and reflects comparability. FERC Stats. & Regs. para. 
31,005 at 31,141.
    \437\ Given the brief comment period on the compliance filings, 
the Commission required public utilities to serve copies of their 
compliance filings (via overnight delivery) on: all participants in 
their current open access rate proceedings (if applicable); all 
customers that have taken wholesale transmission service from the 
utility after the date of issuance of the Open Access NOPR; and the 
state agencies that regulate public utilities in the states of those 
participants and customers. By order issued July 2, 1996, the 
Commission extended the comment period from 15 days to 30 days.
---------------------------------------------------------------------------

2. Group 2 Public Utilities
    In the Final Rule, the Commission indicated that Group 2 public 
utilities will be treated the same as Group 1 public utilities with 
regard to non-rate terms and conditions, but will be treated slightly 
differently from Group 1 as to rates, since Group 2 utilities have not 
filed any proposed rates.\438\ The Commission required these utilities 
to either: (i) within 60 days following publication of the Final Rule 
in the Federal Register, make section 206 compliance filings that 
contain the non-rate terms and conditions set forth in the Final Rule 
pro forma tariff and identify any terms and conditions that reflect 
regional practices, as discussed below; and (ii) within 60 days 
following publication of the Final Rule in the Federal Register, make 
section 205 filings to propose rates for the services provided for in 
the tariff, including ancillary services; or (iii) make a ``good 
faith'' request for waiver. The Commission added that the rates must 
meet the standards for conforming proposals in the Commission's 
Transmission Pricing Policy Statement and comply with the guidance 
concerning ancillary services set forth in this order.
---------------------------------------------------------------------------

    \438\ FERC Stats. & Regs. at 31,769; mimeo at 396-97.
---------------------------------------------------------------------------

    The Commission explained that intervenors may raise any concerns 
with these filings within 15 days after the filing.\439\ The Commission 
imposed a blanket suspension for all such rate filings and indicated 
that they will go into effect, subject to refund, 60 days after the 
publication of this Rule in the Federal Register (the same day on which 
the terms and conditions of the compliance tariffs go into effect).
---------------------------------------------------------------------------

    \439\ The Commission held that Group 2 public utilities must 
serve a copy of their filings (via overnight delivery) on all 
customers that have taken wholesale transmission service from them 
since March 29, 1995 (the date of issuance of the Open Access NOPR) 
and on the state agencies that regulate public utilities in the 
states where those customers are located. By order issued July 2, 
1996, the Commission extended the comment period from 15 days to 30 
days.

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[[Page 12365]]

3. Clarification Regarding Terms and Conditions Reflecting Regional 
Practices
    In the Final Rule, the Commission explained that it had built a 
degree of flexibility into the tariffs to accommodate regional and 
other differences. \440\ It explained that certain non-rate Final Rule 
pro forma tariff provisions specifically allow utilities either to 
follow the terms of the provision or to use alternatives that are 
reasonable, generally accepted in the region, and consistently adhered 
to by the transmission provider (e.g., time deadlines for scheduling 
changes, time deadlines for determining available capacity). In 
addition, it explained that other tariff provisions require utilities 
to follow Good Utility Practice (section 1.14 of the Final Rule pro 
forma tariff).
---------------------------------------------------------------------------

    \440\ FERC Stats. & Regs. at 31,769-70; mimeo at 397-98.
---------------------------------------------------------------------------

4. Future Filings
    In the Final Rule, the Commission indicated that once the 
compliance tariff and conforming rates go into effect, which would be 
60 days after publication of the Rule in the Federal Register, a public 
utility (either Group 1 or Group 2) may file pursuant to section 205 a 
tariff with terms and conditions that differ from those set forth in 
this Rule, provided that, among other things, it demonstrates that such 
terms and conditions are consistent with, or superior to, those in the 
compliance tariff.<SUP>441 However, the Commission emphasized that the 
public utility may not seek to litigate fundamental terms and 
conditions set forth in the Final Rule. In addition, the Commission 
explained that the public utility may file whatever rates it believes 
are appropriate, consistent with the Transmission Pricing Policy 
Statement.
---------------------------------------------------------------------------

    \441\ FERC Stats. & Regs. at 31,770; mimeo at 398-99.
---------------------------------------------------------------------------

5. Waiver
    In the Final Rule, the Commission found that it is reasonable to 
permit certain public utilities for good cause shown to file, within 60 
days after the Rule is published in the Federal Register, requests for 
waiver from some or all of the requirements of this Rule.<SUP>442 The 
Commission explained that the filing of a request in good faith for a 
waiver from the requirement to file an open access tariff will 
eliminate the requirement that such public utility make a compliance 
filing unless thereafter ordered by the Commission to do so. The 
Commission emphasized, however, that it will not exempt such public 
utility from providing, upon request, transmission services consistent 
with the requirements of the Final Rule.
---------------------------------------------------------------------------

    \442\ FERC Stats. & Regs. at 31,770; mimeo at 399-400.
---------------------------------------------------------------------------

Rehearing Requests

    Wisconsin Municipals asserts that the Commission should ``require 
utilities (if requested by their customers) to honor the settlements to 
which they have agreed and to file the pro forma tariff, modified to 
incorporate settlement provisions that exceed the minimum provisions of 
the pro forma tariff, as their implementational filing.'' 
Alternatively, it asks that the Commission ``require parties with 
settlements to make a Section 205 filing one day following their 
implementation filing, change any rates, terms and conditions in the 
pro forma tariff as necessary to incorporate any superior provisions 
from their settlement tariffs into the pro forma tariff, and seek any 
waivers necessary to make the settlement tariff effective 
immediately.'' (Wisconsin Municipals at 7-10).
    Blue Ridge requests rehearing of the ``unbalanced tariff 
implementation process that rolls over the due process rights of 
transmission customers.'' It asserts that utilities should not have the 
right to file a ```Good Utility Practices,' blank check variance for 
regional practices in the compliance docket.'' (Blue Ridge at 33-35). 
Blue Ridge further requests that Group 1 utilities file compliance 
tariffs in the same docket as their pending open access dockets and 
asks that subsequent changes be in a separate docket as a new general 
rate case. Blue Ridge also states that the Commission should explicitly 
mention that customers have the right to file section 206 requests to 
change the tariffs.
    Indianapolis P&L argues that the pricing requirements are unjust, 
unreasonable, unlawful, confiscatory and an abuse of discretion as to 
Indianapolis P&L. It asserts that its rates are not based on embedded, 
original cost, but, as a matter of Indiana law, its utility property is 
valued at the ``fair value,'' which exceeds the embedded original cost 
of such property. It declares that it is impossible for Indianapolis 
P&L to comply with both the comparability requirement and the 
requirement that transmission rates be based on original cost. It 
states that the requirement to provide transmission service and 
generation-based ancillary services at rates based on original cost is 
not comparable to Indianapolis P&L's own use of its assets. 
Accordingly, it argues that the Commission should allow Indianapolis 
P&L to set its initial open access rates on a fair value, long-run 
marginal cost basis. Alternatively, it states that the Commission could 
grant Indianapolis P&L a waiver from the requirements of the Open 
Access Rule.
    Indianapolis P&L further argues that the imposition of an 
obligation to enlarge generation to provide ancillary services is 
beyond the Commission's statutory authority. It explains that 
Indianapolis P&L is an incidental transmission owner and a relatively 
small public utility and asks that the Commission grant it waiver from 
the requirements of open access and OASIS. In deciding whether to grant 
a waiver, it asserts that the Commission should also consider system 
size and configuration, the amount of wholesale revenues or MWH sales, 
or the availability of competing transmission paths.
    Union Electric argues that the final rules violate procedural due 
process and that the implementation schedule is unrealistically 
ambitious. It argues that where the final rules call for changes from 
the NOPRs that could not be reasonably anticipated, they amount to 
deprivation of due process and rights to fairness in the administrative 
process. Indeed, it points out, the Commission itself has not even 
completed its promulgation of the OASIS Final Rule. Union Electric is 
concerned that it has not had an adequate time to comply with and 
comment on the rules.

Commission Conclusion

    Wisconsin Municipals has misinterpreted the Commission's findings 
in Order No. 888, and thus its concerns are without merit. While it is 
true that Order No. 888 requires all public utilities to make 
compliance filings containing the non-price terms and conditions set 
forth in the Final Rule pro forma tariff,<SUP>443 Order No. 888 also 
states that ``we are not abrogating existing requirements and 
transmission contracts generically. * * *'' <SUP>444 In short, the 
Commission is not requiring (or even generically allowing) the 
abrogation of existing transmission contracts, but is only requiring 
that jurisdictional transmission providers must also offer transmission 
service under the Final Rule pro forma tariff in addition to whatever 
commitments the provider will continue to have under its existing 
contracts. <SUP>445
---------------------------------------------------------------------------

    \443\ FERC Stats. & Regs. at 31,768-69; mimeo at 394-96.
    \444\ FERC Stats. & Regs. at 31,665; mimeo at 87-88.
    \445\ See also discussion of prior settlements in Section 
IV.D.1.c.(2) (Energy Imbalance Bandwidth).
---------------------------------------------------------------------------

    As to Wisconsin Municipals' assertions that prior individual 
settlement provisions may exceed the

[[Page 12366]]

minimum provisions of the pro forma tariff, the Commission believes 
that such arguments should be addressed on a case-by-case basis. 
<SUP>446
---------------------------------------------------------------------------

    \446\ See IES Utilities, Inc., et al., 78 FERC para. 61,023 
(1997).
---------------------------------------------------------------------------

    Two additional points are pertinent. First, we note that although 
we are not generically abrogating existing transmission contracts, 
utilities retain whatever existing rights they had to propose 
unilateral changes under section 205 of the FPA if they want to convert 
a customer to service under the tariff, and customers retain their 
section 206 right to seek reformation of existing transmission 
contracts if they are unjust, unreasonable, unduly discriminatory or 
preferential. Second, where a utility has treated similarly-situated 
customers differently--serving one under a more favorable bilateral 
contract and another under a less favorable tariff provision--
traditional undue discrimination remedies may be available.
    We deny Blue Ridge's rehearing requests because the Commission does 
not intend to assume the regulatory responsibility of identifying in 
the first instance all of the regional practices around the country 
that could (and should) properly be reflected in the compliance 
tariffs. Transmission customers opposed to deviations related to 
regional practices not only had the opportunity to protest the 
compliance filings when they were tendered, <SUP>447 but these 
customers also have the right to file section 206 requests to change 
these tariffs at any time. In addition, Blue Ridge's request that 
customers be given 45 days to respond to compliance filings instead of 
15 days is moot. In an order issued July 2, 1996,<SUP>448 we took three 
actions to address this concern: (1) we gave entities 30 days, instead 
of 15 days, to respond to Order No. 888 compliance filings; (2) we 
agreed to post an electronic version of all Order No. 888 compliance 
filings on the Commission's Electronic Bulletin Board; and (3) we 
required all public utilities making a compliance filing to also serve 
a copy of their filing on electronic diskette to any eligible customer 
or state regulatory agency requesting a copy. We believe that these 
actions not only provided all interested parties with access to the 
compliance filings more quickly, but also provided these parties 
sufficient time to analyze the information once they received 
it.<SUP>449 Moreover, the time periods provided for making and 
responding to Order No. 888 compliance filings have expired.
---------------------------------------------------------------------------

    \447\ We do note that most of these concerns have been addressed 
in our orders dealing with the compliance filings on non-rate terms 
and conditions. See, e.g., Atlantic City Electric Company, et al., 
77 FERC para. 61,144 (1996); Allegheny Power System, Inc., et al., 
77 FERC para. 61,266 (1996).
    \448\ 76 FERC para. 61,009 at 61,026-27 (1996) (July 2 Order).
    \449\ We also note that utilities were required in Order No. 888 
to explicitly identify any regional practices in their compliance 
filings.
---------------------------------------------------------------------------

    With regard to Blue Ridge's first clarification request, we provide 
the following guidance. Utilities that had pending open access filings 
at the time that the Final Rule was implemented had the non-price terms 
and conditions of those pending tariffs superseded by their Order No. 
888 compliance filings. Any customer concerns about the non-rate tariff 
terms and conditions in the compliance filing should be raised in the 
compliance docket, and any future customer concerns should be raised in 
a separate, future section 206 complaint filed by the customer.
    Furthermore, we reject Indianapolis P&L's rate issue because, if 
this utility believes that it operates under special circumstances that 
require it to use ``non-conforming'' pricing methods, it is free to 
file such a proposal under section 205. The merits of Indianapolis 
P&L's arguments are more appropriately addressed in such a section 205 
proceeding. The Commission will not alter its generic policy (which is 
the subject of this rulemaking) merely to address the particular needs 
of one party.
    In addition, with regard to both of Indianapolis P&L's concerns, we 
note that pursuant to the Commission's July 2 Order, the Commission 
indicated that it would not address waiver requests in a generic 
proceeding and that parties would have to file such requests separately 
for separate docketing. We further note that Indianapolis P&L filed a 
separate waiver request on July 9, 1996, which was docketed as OA96-
81.<SUP>450
---------------------------------------------------------------------------

    \450\ By order issued September 11, 1996, the Commission denied 
Indianapolis P&L's requested waiver of all the requirements of Order 
No. 888. On October 8, 1996, Indianapolis P&L sought rehearing of 
that order and a stay of the requirements of Order No. 888. These 
pleadings are now pending before the Commission.
---------------------------------------------------------------------------

    We also reject Union Electric's argument that the final rules 
violate procedural due process. Union Electric has had every 
opportunity to raise arguments with regard to every step in the 
Commission's derivation and implementation of the final rules. 
Moreover, with regard to Union Electric's claim that it was given an 
inadequate amount of time to comprehend and implement the final rules, 
we note that virtually every public utility, including Union Electric, 
complied with the Open Access Rule on a timely basis, and there have 
been very few complaints that the rules are hard to comprehend.

I. Federal and State Jurisdiction: Transmission/Local Distribution

    In the Final Rule, the Commission explained that after reviewing 
the extensive analysis of the FPA, legislative history, and case law 
contained in both the initial Stranded Cost NOPR and in the Open Access 
NOPR, and the comments received on that analysis, it reaffirmed its 
assertion of jurisdiction over the transmission component of an 
unbundled interstate retail wheeling transaction.<SUP>451 The 
Commission also reaffirmed and clarified its determinations regarding 
the tests to be used to determine what constitute Commission-
jurisdictional transmission facilities and what constitute state-
jurisdictional local distribution facilities in situations involving 
unbundled wholesale wheeling and unbundled retail wheeling.
---------------------------------------------------------------------------

    \451\ FERC Stats. & Regs. at 31,780-85; mimeo at 427-42.
---------------------------------------------------------------------------

    The Commission also explained that where states unbundle retail 
sales, it will give deference to their determinations as to which 
facilities are transmission and which are local distribution, provided 
that the states, in making such determinations, apply the seven 
criteria discussed in the NOPR and reaffirmed by the Commission. In 
addition, the Commission clarified that there is an element of local 
distribution service in any unbundled retail transaction, and further 
clarified other aspects of its jurisdictional ruling to preserve state 
jurisdiction over matters that are of local concern and will remain 
subject to state jurisdiction if retail unbundling occurs.
    The Commission reaffirmed its legal determination that if unbundled 
retail transmission in interstate commerce occurs voluntarily by a 
public utility or as a result of a state retail access program, this 
Commission has exclusive jurisdiction over the rates, terms, and 
conditions of such transmission. The Commission found compelling the 
fact that section 201 of the FPA, on its face, gives the Commission 
jurisdiction over transmission in interstate commerce (by public 
utilities) without qualification.
    The Commission further explained that when a retail transaction is 
broken into two or more products that are sold separately, the 
jurisdictional lines change. In this situation, the Commission 
emphasized that the state clearly retains jurisdiction over the sale of 
the power, but the unbundled

[[Page 12367]]

transmission service involves only the provision of ``transmission in 
interstate commerce'' which, under the FPA, is exclusively within the 
jurisdiction of the Commission.
    The Commission recognized that in asserting jurisdiction over 
unbundled retail transmission in interstate commerce by public 
utilities, it was in no way asserting jurisdiction to order retail 
transmission directly to an ultimate consumer. It explained that its 
assertion of jurisdiction is that if unbundled retail transmission in 
interstate commerce by a public utility occurs voluntarily or as a 
result of a state retail wheeling program, the Commission has exclusive 
jurisdiction over the rates, terms, and conditions of such transmission 
and public utilities offering such transmission must comply with the 
FPA by filing proposed rate schedules under section 205.
    The Commission further clarified that nothing in its jurisdictional 
determination changes historical state franchise areas or interferes 
with state laws governing retail marketing areas of electric utilities. 
It explained that while its jurisdiction cannot affect whether and to 
whom a retail electric service territory (marketing area) is to be 
granted by the state, and whether such grant is exclusive or non-
exclusive, neither can state jurisdiction affect this Commission's 
exclusive jurisdiction over transmission in interstate commerce by 
public utilities.
    The Commission also adopted a new section 35.27(b) as follows:

    Nothing in this part (i) shall be construed as preempting or 
affecting any jurisdiction a state commission or other state 
authority may have under applicable state and federal law, or (ii) 
limits the authority of a state commission in accordance with state 
and federal law to establish (a) competitive procedures for the 
acquisition of electric energy, including demand-side management, 
purchased at wholesale, or (b) non-discriminatory fees for the 
distribution of such electric energy to retail consumers for 
purposes established in accordance with state law.

    With respect to the Commission's adoption of the Open Access NOPR's 
functional/technical tests for determining what facilities are 
Commission-jurisdictional facilities used for transmission in 
interstate commerce and what facilities are state-jurisdictional local 
distribution facilities, the Commission concluded that it could not 
divine a bright line for unbundled retail transmission by the public 
utility that previously provided bundled retail service to the end 
user. The Commission added that the limited case law, including 
Connecticut Light & Power Company v. FPC (CL&P) and Federal Power 
Commission v. Southern California Edison Company (the Colton 
case),<SUP>452 supports a case-by-case determination.<SUP>453 
Accordingly, the Commission stated that its technical test, with its 
seven indicators, will permit reasoned factual determinations in 
individual cases.
---------------------------------------------------------------------------

    \452\ 324 U.S. 515 (1945) (CL&P); 376 U.S. 205 (1964) (Colton).
    \453\ The Commission included a detailed legal analysis in 
Appendix G to Order No. 888. The Commission explained that it was 
particularly persuaded by the Supreme Court's statement that whether 
facilities are used in local distribution is a question of fact to 
be decided by the Commission as an original matter. See CL&P, 324 
U.S. at 534-35).
---------------------------------------------------------------------------

    The Commission made two clarifications regarding local distribution 
in the context of retail wheeling. First, it explained that even if its 
technical test for local distribution facilities were to identify no 
local distribution facilities for a specific transaction, states have 
authority over the service of delivering electric energy to end users. 
Second, the Commission explained that through their jurisdiction over 
retail delivery services, states have authority not only to assess 
retail stranded costs but also to assess charges for so-called stranded 
benefits, such as low-income assistance and demand-side management.
    Thus, under this interpretation of state/federal jurisdiction, the 
Commission explained, customers have no incentive to structure a 
purchase so as to avoid using identifiable local distribution 
facilities in order to bypass state jurisdiction and thus avoid being 
assessed charges for stranded costs and benefits.
    The Commission further determined that it is appropriate to provide 
deference to state commission recommendations regarding certain 
transmission/local distribution matters that arise when retail wheeling 
occurs.
    In instances of unbundled retail wheeling that occurs as a result 
of a state retail access program, the Commission indicated that it will 
defer to recommendations by state regulatory authorities concerning 
where to draw the jurisdictional line under the Commission's technical 
test for local distribution facilities, and how to allocate costs for 
such facilities to be included in rates, provided that such 
recommendations are consistent with the essential elements of the Final 
Rule.<SUP>454 Moreover, the Commission indicated that it will consider 
jurisdictional recommendations by states that take into account other 
technical factors that the state believes are appropriate in light of 
historical uses of particular facilities.
---------------------------------------------------------------------------

    \454\ In order to give such deference, the Commission noted its 
expectation that state regulators will specifically evaluate the 
seven indicators and any other relevant facts and make 
recommendations consistent with the essential elements of the Rule.
---------------------------------------------------------------------------

    As a means of facilitating jurisdictional line-drawing, the 
Commission stated that it will entertain proposals by public utilities, 
filed under section 205 of the FPA, containing classifications and/or 
cost allocations for transmission and local distribution facilities. 
However, the Commission explained that, as a prerequisite to filing 
transmission/local distribution facility classifications and/or cost 
allocations with the Commission, utilities must consult with their 
state regulatory authorities. If the utility's classifications and/or 
cost allocations are supported by the state regulatory authorities and 
are consistent with the principles established in the Final Rule, the 
Commission indicated that it will defer to such classifications and/or 
cost allocations.
    Furthermore, the Commission stated that deference to state 
commissions with regard to rates, terms, and conditions may be 
appropriate in some circumstances. The Commission explained that when 
unbundled retail wheeling in interstate commerce occurs, the 
transaction has two components for jurisdictional purposes--a 
transmission component and a local distribution component. It again 
emphasized that the Commission has jurisdiction over facilities used 
for the transmission component of the transaction, and the state has 
jurisdiction over facilities used for the local distribution component. 
Thus, the Commission stated, the rates, terms and conditions of 
unbundled retail transmission by a public utility must be filed at the 
Commission. However, the Commission added, if the unbundled retail 
wheeling occurs as part of a state retail access program, it may be 
appropriate to have a separate retail transmission tariff <SUP>455 to 
accommodate the design and special needs of such programs. In such 
situations, the Commission indicated that it will defer to state 
requests for variations from the FERC wholesale tariff to meet these 
local concerns, so long as the separate retail tariff is consistent 
with the Commission's open access policies and comparability principles 
reflected in the tariff prescribed by the Final Rule. In addition, the 
Commission indicated that

[[Page 12368]]

the rates must be consistent with its Transmission Pricing Policy 
Statement, and the guidance set forth in Order No. 888 concerning 
ancillary services. <SUP>456
---------------------------------------------------------------------------

    \455\ The Commission noted that such a tariff could be different 
from the tariff that applies to wholesale customers, but that such 
tariff would still be filed with the Commission under FPA section 
205.
    \456\ In applying the principles of the Final Rule to retail 
transmission tariffs, the Commission emphasized that it clearly 
cannot order retail wheeling directly to an ultimate consumer. 
(citing FPA section 212(h)).
---------------------------------------------------------------------------

    The Commission also expressed concern, just as it did with buy-sell 
arrangements in the gas industry, that buy-sell arrangements can be 
used by parties to obfuscate the true transactions taking place and 
thereby allow parties to circumvent Commission regulation of 
transmission in interstate commerce. Thus, the Commission reaffirmed 
its conclusion that it has jurisdiction over the interstate 
transmission component of transactions in which an end user arranges 
for the purchase of generation from a third-party. Moreover, the 
Commission indicated that it will address these transactions on a case-
by-case basis.

Rehearing Requests

Oppose Commission Assertion of Jurisdiction Over Unbundled Retail 
Transmission

    Several state commissions indicate that, recognizing that the case 
law is not dispositive concerning the question of unbundled retail 
transmission services (either because the cases do not involve the 
transmission of power to retail customers or ``fence off'' local 
distribution from federal regulation), at least one court (Wisconsin-
Michigan Power Company v. FPC, 197 F.2d 472 (7th Cir. 1952), cert. 
denied, 345 U.S. 934 (1953)) explicitly applied the wholesale/retail 
distinction to distinguish transmission and local distribution 
services. <SUP>457 Thus, they argue, the Commission should apply the 
wholesale versus retail analysis to the question of unbundled retail 
transmission.
---------------------------------------------------------------------------

    \457\ E.g., NARUC, WI Com, WY Com.
---------------------------------------------------------------------------

    IL Com asserts that retail transmission by a public utility 
directly to an end user has always (even before the FPA was enacted) 
been subject to regulation by the states. It contends that no change in 
law has occurred which justifies the Commission's claim of expanded 
jurisdiction. Moreover, it disagrees with the Commission's conclusion 
that the unbundled delivery by the previous public utility generation 
supplier directly to an end user is in interstate commerce. It argues 
that the FPA was never intended to disturb the jurisdiction of state 
regulators that existed prior to its passage and that retail 
transmission of electric energy by a public utility to an end user was 
under state jurisdiction before the Attleboro decision and has remained 
under state jurisdiction in the over sixty years following Attleboro. 
Even after unbundling, according to IL Com, transmission to a retail 
customer still involves a retail sale of transmission.
    NARUC and VA Com assert that the legislative history provides 
little support for the Commission's conclusion that the act of 
unbundling generation from delivery serves to shift jurisdiction from a 
state commission to the Commission. If anything, they contend, the 
jurisdictional structure of the FPA is predicated on the distinction 
between retail and wholesale transactions, not bundled and unbundled 
services. They assert that the Commission should conclude that the 
rates, terms and conditions of service for delivery of power by a 
utility to an end-use customer are subject to the jurisdiction of the 
state commission regulating the utility, regardless of the identity of 
the party generating or reselling the power or the facilities used to 
transport the power.
    NARUC asserts that the Commission did not address a point raised in 
NARUC's reply comments as to how the removal of generation serves to 
unbundle the retail delivery function into separate transmission and 
distribution services. It maintains that the Commission simply assumes 
that a resulting transmission transaction is created when power is sold 
to a retail consumer by someone other than the utility delivering the 
power. <SUP>458
---------------------------------------------------------------------------

    \458\ See also IA Com (use of a utility's transmission system to 
serve its own retail customers is a bundled part of the retail sale 
transaction, which supports a simpler jurisdictional test holding 
that a movement of power by the last utility in any chain of 
delivery to a retail customer is a distribution transaction).
---------------------------------------------------------------------------

    MI & NH Coms ask the Commission to vacate those portions of the 
Rule that find that the Commission has jurisdiction over the 
transmission component of an unbundled retail sale in a local retail 
wheeling transaction. They assert that the Commission should confine 
its activity to wholesale transactions or those interstate transactions 
that do not implicate matters of local concern. They argue that the 
dual federal/state regulatory scheme establishes that Congress' intent 
is that state regulation of retail wheeling is not preempted by federal 
law as established in FPA section 201. They oppose unnecessary federal 
intrusion into local matters under a one-size-fits-all approach and 
assert that the retail wheeling initiatives in New Hampshire and 
Michigan are tailored to the unique utility environment in each state.
    Central Illinois Light argues that unbundling of retail electric 
service does not change the states' longstanding jurisdiction over 
retail electric service and local distribution, even when that service 
involves the use of transmission in interstate commerce. It asserts 
that 201(b)(1) (``transmission of electric energy in interstate 
commerce'') cannot be read in a vacuum.
    MN DPS & MN Com and OH Com assert that the Commission should have 
no role in the regulation of retail services, be they bundled or 
unbundled. They argue that, in refusing to grant the Commission 
authority over retail wheeling, Congress left jurisdiction over retail 
electric service to the states. They conclude that the Final Rule 
contains insufficient legal and/or policy justification for the 
Commission's assertion of jurisdiction over unbundled retail 
transmission services.
    MN DPS & MN Com assert: ``FERC bases its usurpation of state 
authority over retail transmission rates on its claim that 
balkanization would occur without the assertion of FERC authority. 
Therefore, the parties are entitled to rehearing so that this essential 
issue can be further analyzed.'' (MN DPS & MN Com at 1-3).
    FL Com argues that the Commission has not justified why the act of 
unbundling prices expands the Commission's jurisdiction into retail 
marketing areas. It argues that Section 212(g) of the FPA has the 
effect of prohibiting the Commission from usurping existing state 
jurisdiction over retail transmission service, whether bundled or 
unbundled. According to FL Com, FERC's jurisdiction over transmission 
terminates at the territorial boundary of each electric utility in 
Florida. It supports wheeling in jurisdiction for state commissions and 
wheeling out and wheeling through jurisdiction for the Commission.
    IN Com opposes federalization of retail wheeling transactions 
within a state's boundaries as contrary to the FPA's legislative 
history and case law.
    NJ BPU asserts that by claiming jurisdiction over unbundled retail 
transmission, the Commission is creating a disincentive for states to 
implement retail access because, by ordering retail access, the states 
may be relinquishing their jurisdiction over unbundled retail 
transmission terms and conditions--jurisdiction that they would 
maintain under a bundled scenario. <SUP>459 PA Com argues that the 
Commission does not have the authority

[[Page 12369]]

to order retail wheeling and that the jurisdictional formula is 
challengeable on engineering and legal grounds. It concludes that the 
Commission does not have jurisdiction over unbundled interstate retail 
transmission service. PA Com notes that the 1996 House and Senate 
hearings have raised the question whether the Commission has the 
statutory authority to restructure the electric industry. PA Com 
questions the Commission's definition of the ``traditional tasks of 
state and federal regulators'' on the basis of section 201(b) of the 
FPA, the Supremacy Clause, and the Tenth Amendment of the U.S. 
Constitution.
---------------------------------------------------------------------------

    \459\ See also PA Com.
---------------------------------------------------------------------------

Support Broader Assertion of Jurisdiction by the Commission Over Retail 
Wheeling

    NY Utilities declare that the Commission has jurisdiction over 
retail wheeling from the source to the load, but does not have 
jurisdiction over transmission in bundled retail service. They assert 
that the Commission's reliance on state jurisdictional local 
distribution as a predicate to abstain from allowing retail wheeling 
stranded cost recovery is without foundation. They further assert that 
a unique element that sets local distribution apart from transmission 
is not the size of the facility or the length of travel, but that 
transportation is bundled with a retail sale. According to NY 
Utilities, the plain meaning of the FPA shows that local distribution 
is bundled retail service. They claim that the legislative history, to 
the extent necessary, and court cases support FERC jurisdiction over 
all aspects of retail wheeling, but makes clear that the Commission 
cannot regulate bundled retail service. They add that the NGA also 
demonstrates that local distribution means bundled retail service.

Commission Conclusion

    In concluding that this Commission has exclusive jurisdiction over 
the rates, terms and conditions of unbundled retail transmission by 
public utilities in interstate commerce, the Commission in Order No. 
888 thoroughly examined the statutory language of the FPA and its 
legislative history, and relevant FPA and NGA case law. While the state 
commissions on rehearing would like us to draw a bright line that gives 
them, to varying degrees, jurisdiction over retail interstate 
transmission by public utilities, no party on rehearing has raised any 
legislative history or case law that was not previously considered and 
that would support the proposition that states have jurisdiction over 
any unbundled transmission in interstate commerce. As explained below, 
we reaffirm our jurisdictional interpretation on rehearing and believe 
that it is supported by the recent decision in United Distribution 
Companies v. FERC.<SUP>460
---------------------------------------------------------------------------

    \460\ 88 F.3d 1105, 1152-53 (1996) (United Distribution 
Companies).
---------------------------------------------------------------------------

    Many of the rehearing arguments focus on the fact that states 
historically (even prior to the FPA) regulated retail transmission 
insofar as it was a component of bundled electric service to an end 
user, and they argue that by asserting jurisdiction over unbundled 
retail transmission, the Commission is somehow ``taking away'' 
jurisdiction the states previously had. The flaw in these arguments is 
their inherent assumption that jurisdiction over transmission service 
turns upon the question of whether the transmission service is being 
provided for ``wholesale'' or ``retail'' power sales. That is not the 
case. The question of jurisdiction rather turns upon the extent of the 
Commission's exclusive jurisdiction over transmission in interstate 
commerce under the FPA. The fact that states historically regulated 
most retail transmission service as a part of a bundled retail power 
sale is not the result of a legal requirement; it is the practical 
result of the way electricity has historically been bought and sold. 
However, the shape of power sales transactions is rapidly changing. 
Rather than claiming ``new'' jurisdiction, the Commission is applying 
the same statutory framework to a business environment in which, as 
discussed below, retail sales and transmission service are provided in 
separate transactions.
    In the past, retails ales occurred almost exclusively on a bundled 
basis (i.e., the same entity provided a delivered product called 
electric energy and transmission was part and parcel of that product). 
The FPA clearly reserves the right to regulate retail sales of electric 
energy to the states. As we explained in the Final Rule, however, in 
today's markets, and increasingly in the future as more states adopt 
retail wheeling programs, retail transactions are being broken into 
products that are being sold separately: transmission and generation. 
Moreover, these products are being sold increasingly by two or more 
different entities. For example, a transaction may involve transmission 
service from one or more transmission providers who move power from a 
distant generation supplier, over the interstate transmission grid, to 
an end user. Because these types of products and transactions were not 
prevalent in the past, the jurisdictional issue before us did not arise 
and, contrary to IL Com's argument, the Commission cannot be viewed as 
``disturbing'' the jurisdiction of state regulators prior to and after 
the Attleboro case.<SUP>461
---------------------------------------------------------------------------

    \461\ Public Utilities Commission v. Attleboro Steam & Electric 
Co., 273 U.S. 83 (1927).
---------------------------------------------------------------------------

    As we also explained in the Final Rule, the legislative history of 
the FPA and the relevant case law similarly reflect the historical 
market structure in which electricity and transmission generally were 
bought on a bundled basis.<SUP>462 Today's unbundled world simply was 
not contemplated and the cases do not resolve dispositively this 
jurisdictional issue. The case law focuses primarily on the bright line 
between wholesale sales and retail sales of energy, and transmission in 
interstate as opposed to intrastate commerce. It does not address 
unbundled retail interstate transmission.<SUP>463 We therefore have 
interpreted the case law in light of changed circumstances and have 
relied in the first instance on the plain wording of the statute. We 
find compelling that section 201 of the FPA, on its face, gives the 
Commission jurisdiction over transmission in interstate commerce 
without qualification; unlike our jurisdiction over sales of electric 
energy, which section 201 specifically limits to sales at wholesale, 
the statute does not limit our transmission jurisdiction over public 
utilities to wholesale transmission.
---------------------------------------------------------------------------

    \462\ The case law is addressed extensively in Appendix G to the 
Final Rule and will not be repeated here.
    \463\ On rehearing, several parties argue that at least one 
court case, Wisconsin-Michigan Power Co. v. FPC, 197 F.2d 472 (7th 
Cir. 1952), cert. denied, 345 U.S. 934 (1953) explicitly applied the 
wholesale/retail distinction to distinguish transmission and local 
distribution services. The Commission discussed this case in detail 
in Appendix G to the Final Rule, FERC Stats. & Regs. at 31,974-75; 
mimeo at 22-25. As we stated there, the court's interpretation of 
the legislative history of the FPA was at odds with both the plain 
words of the statute as well as the language of the House Report on 
the FPA (H.R. Rep. No. 1318 at 27). It also did not mention the 
Senate Report on the FPA, which clearly recognized jurisdiction over 
all interstate transmission lines, whether or not a sale of energy 
is carried by those lines (S. Rep. No. 621 at 48). We therefore 
reject arguments that this single case is in any way dispositive of 
the issue before us.
---------------------------------------------------------------------------

    Since the time Order No. 888 issued, the D.C. Circuit has addressed 
a similar issue in interpreting section 1(b) of the NGA, the provision 
that parallels section 201(b) of the FPA. Under section 1(b), the 
Commission's jurisdiction does not apply ``to the local distribution of 
natural gas or to the facilities used for such distribution.'' 
Similarly, under section 201(b) of the FPA, the Commission shall not 
have jurisdiction, except as specifically provided, ``over

[[Page 12370]]

facilities used for the generation of electric energy or over 
facilities used in local distribution * * *'' In responding to 
arguments regarding the scope of state authority over ``local 
distribution'' of natural gas, the court distinguished between bundled 
and unbundled sales:

    States have been--and are still--permitted to regulate LDCs' 
bundled sales of natural gas to end-users because those transactions 
include transportation over local mains and the retail sales of gas. 
In contrast, states have never regulated the terms and conditions of 
interstate pipeline transportation. When the gas sales element is 
severed--i.e., unbundled--from the transactions, FERC retains 
jurisdiction over the interstate transportation component.'' [United 
Distribution Companies, 88 F.3d at 1153 (footnote omitted) (emphasis 
in original).]

The court's reasoning is also applicable to and supports our 
jurisdictional determination in Order No. 888.
    Several state commissions point to section 212(h) of the FPA and 
argue that Congress, in refusing to grant the Commission authority to 
order retail wheeling, left all jurisdiction over retail transmission 
to the states. We disagree. What Congress did in section 212(h) was to 
prohibit us from ordering transmission directly to an ultimate 
consumer. We readily recognize and respect this prohibition. However, 
the ability to order retail wheeling is a separate issue from whether 
we have jurisdiction over the rates, terms and conditions of retail 
wheeling in interstate commerce that is ordered by a state or that is 
provided voluntarily. Congress, in enacting section 212(h), did nothing 
to modify our jurisdiction under sections 201, 205 and 206 over the 
rates, terms and conditions of interstate transmission by public 
utilities.
    Similarly, we reject FL Com's arguments that section 212(g) of the 
FPA prohibits the Commission from asserting any jurisdiction over 
unbundled retail transmission. Section 212(g) prohibits the Commission 
from issuing an order that is inconsistent with any state law that 
governs retail marketing areas of electric utilities. As we stated in 
the Final Rule, while our jurisdiction cannot affect whether and to 
whom a retail electric service territory (marketing area) is to be 
granted by the state, and whether such grant is exclusive or non-
exclusive, neither can state jurisdiction affect this Commission's 
exclusive jurisdiction over the rates, terms and conditions of 
transmission in interstate commerce by public utilities. We also reject 
arguments by the FL Com that this Commission's jurisdiction over 
transmission terminates at the territorial boundary of each electric 
utility in Florida. This argument is flatly contrary to the 
longstanding interpretation of the FPA by the United States Supreme 
Court.<SUP>464
---------------------------------------------------------------------------

    \464\ See FPC v. Southern California Edison Co., 376 U.S. 205 
(1964) (Colton case). IN Com makes a similar argument and opposes 
``federalization'' of retail wheeling within a state's boundaries. 
We reject this argument on the same basis.
---------------------------------------------------------------------------

Commission's Seven Factor Test

    IL Com argues that the Commission should withdraw its technical 
test. It contends that retail wheeling jurisdiction should follow 
function and that the function served by public utility facilities in 
providing retail service does not change upon the unbundling of service 
to retail customers. According to IL Com, Commission jurisdiction would 
extend to the service of delivering electric energy by a public utility 
to wholesale customers, regardless of the nature and extent of the 
public utility's facilities used to make that delivery. Similarly, it 
asserts, state jurisdiction would extend to the service of delivering 
electric energy by a public utility directly to retail customers, 
regardless of the nature and extent of the public utility's facilities 
used to make that delivery.
    NARUC argues that the seven-factor test does not result in the 
bright line discussed in FPC v. Southern California Edison Company, 376 
U.S. 205 (1964). The facility-by-facility categorization of utility 
systems on a company-specific basis, it asserts, is hardly consistent 
with the Court's decision to make case-by-case analysis unnecessary.
    OH Com asserts that the seven factors provide no useful insight 
into the nature of local distribution service. It adds that reliance 
upon technical tests to determine local distribution lacks legal 
foundation. It further contends that the jurisdictional bright line 
established by Congress focuses upon the nature of the transaction, not 
the functional or technical characteristics of a particular wire, in 
determining whose jurisdictional authority attaches to a particular 
transaction and facilities. It concludes that the Commission should 
adopt the Ohio-proposed retail marketing area ``wheeling in'' 
jurisdictional approach.
    PA Com contends that the Commission's seven indicia are not 
acceptable measures of local distribution and challenges each factor.
    NH & MI Coms declare that the criteria for distinguishing 
transmission facilities from local distribution facilities should not 
be limited to the seven given in the Rule, but should allow 
consideration of any other relevant criteria for separating local 
concerns from matters legitimately federal in nature.
    NJ BPU argues that the engineering-driven definition does not 
resolve many of the hazy areas. To the extent that the seven factors do 
not reflect or cannot be reconciled with the particular circumstances, 
it contends that the states may be hamstrung in their ability to make 
reasoned decisions that comport with Order No. 888.<SUP>465
---------------------------------------------------------------------------

    \465\ See also WI Com (criteria do not appropriately reflect the 
mixed nature of many facilities in systems that are closely 
integrated and the application of the criteria to the electric 
system in Wisconsin would supplant state jurisdiction over a large 
number of facilities whose primary functions are local reliability 
and retail service).
---------------------------------------------------------------------------

    Similarly, NY Com argues that five of the seven factors (1, 2, 4, 
6, and 7) are not accurate when applied to large metropolitan areas and 
remote rural areas. It asserts that local distribution facilities are 
not necessarily close to retail customers and the assumption that local 
distribution facilities are primarily radial in character fails to 
account for network systems. It adds that reconsignment or 
transportation of power to different markets can and does occur at the 
local distribution level. It further adds that the presence of meters 
is not a discerning characteristic of where interstate transmission 
ends and local distribution begins; meters are frequently not part of 
the transmission/local distribution interface. Nor, according to NY 
Com, are local distribution systems necessarily of reduced voltage. 
Instead of the 7 criteria, NY Com argues that the Commission should 
adopt a functional measure of local distribution based on factors 3 and 
5 (interstate transmission ends and local distribution begins where 
electricity flows into a comparatively restricted geographic area and 
does not flow back out of that area and the power is consumed in that 
area) and on the traditional classification of the facilities by the 
state regulatory body (or what the utility has traditionally classified 
as local distribution).

Commission Conclusion

    Several parties on rehearing do not like the seven-factor technical 
test for local distribution facilities that was set forth in Order No. 
888. That test takes into account both technical and functional 
characteristics of the transaction involved. The parties on rehearing 
propose instead a variety of bright line tests. For example, IL Com 
wants state jurisdiction to extend to the ``service'' of delivering 
electric energy to retail customers, which it would define to give it 
jurisdiction regardless of the

[[Page 12371]]

nature and extent of the facilities used to make the delivery. OH Com 
proposes that the Commission adopt a retail marketing area ``wheeling 
in'' jurisdictional approach which would give it jurisdiction over 
facilities within territorial boundaries.
    In response, we do not interpret the FPA to permit us in effect to 
rewrite the statute to give states jurisdiction over interstate 
transmission services. Moreover, we reject arguments of OH Com that our 
seven-factor test lacks legal foundation, and arguments of NARUC that 
we are somehow bound to develop a bright line test. While Congress 
established a jurisdictional bright line between wholesale and retail 
sales of energy, there is no such bright line that we can divine with 
regard to transmission and local distribution facilities. The Supreme 
Court, in both Colton and CL&P,<SUP>466 has instructed us that whether 
facilities are used in local distribution is a question of fact to be 
decided by the Commission as an original matter. The seven factors will 
permit us to undertake this fact-specific determination.
---------------------------------------------------------------------------

    \466\ See Colton, 376 U.S. at 210 n.6; CL&P, 324 U.S. at 531-36.
---------------------------------------------------------------------------

    We acknowledge the concerns raised by several state commissions 
that the seven-factor test does not, as NJ BPU puts it, resolve many of 
the hazy areas, and that there may be other factors that should be 
taken into account in particular situations. The seven-factor test is 
intended to provide sufficient flexibility to take into account unique 
local characteristics and historical usage of facilities used to serve 
retail customers. We specifically stated in the Final Rule that we will 
consider jurisdictional recommendations by states that take into 
account other technical factors that states believe are appropriate in 
light of historical uses of particular facilities. Moreover, we will 
defer to facility classifications and/or cost allocations that are 
supported by state regulatory authorities. For example, in the ongoing 
California electric utility restructuring proceeding, the Commission 
deferred to the State PUC's recommendations regarding the split between 
state jurisdictional local distribution facilities and Commission-
jurisdictional transmission facilities.<SUP>467
---------------------------------------------------------------------------

    \467\ Pacific Gas and Electric Company, et al., 77 FERC para. 
61,325 at 61,325 (1996).
---------------------------------------------------------------------------

Oppose Transmission of Public Utility Purchases for Sale at Retail

    IL Com objects to the transmission unbundling requirement if it is 
intended to require public utilities to take transmission services 
under their own FERC tariffs for purchases of power intended for 
distribution by the public utility to retail customers. According to IL 
Com, a distinction must be made between the public utility's use of its 
transmission system in cases in which the public utility purchases 
wholesale power for sale for resale, and cases in which the public 
utility purchases wholesale power to serve native load retail 
customers. It argues that the Commission cannot legally regulate, or 
place conditions on, the manner in which a utility uses its 
transmission system to make sales of electric energy at retail. It 
contends that the Commission must exempt public utility power purchases 
for sale at retail from the unbundling requirement. It recommends that 
the Commission insert the words ``for sale for resale'' after the word 
``purchases'' in section 35.28(c)(2) and after the word ``purchase'' in 
section 35.28(c)(2)(i).

Commission Conclusion

    The Commission rejects arguments of IL Com that if unbundled retail 
wheeling occurs either voluntarily or as a result of a state retail 
program, we cannot require the utility to take service under its own 
transmission tariff for sales to retail customers. This requirement is 
a term and condition of unbundled retail interstate transmission 
service and, as explained above, therefore is within our exclusive 
jurisdiction. Additionally, this should not in any way infringe on 
state retail programs or service to retail customers. Rather, it 
ensures that non-discriminatory transmission services are provided to 
all potential retail power competitors.
    Further, as stated previously in Section IV.C.1.b (Transmission 
Providers Taking Service Under Their Tariff), we clarify that a 
transmission provider does not have to ``take service'' under its own 
tariff for the transmission of power that is purchased on behalf of 
bundled retail customers.

Oppose Buy-Sell Transaction Analysis

    PA Com asserts that there is a potential for jurisdictional 
conflict with respect to buy-sell transactions that is a direct 
consequence of the technical-functional test (which PA Com challenges).
    IL Com argues that states have exclusive authority to regulate buy-
sell arrangements as bundled retail sales. It further argues that the 
Commission cannot make a bundled retail sale into an unbundled retail 
sale simply by characterizing it as the functional equivalent of an 
unbundled retail sale; by re-characterizing them the Commission is 
effectively ordering the unbundling of buy-sell arrangements. It 
asserts that buy-sell arrangements on the electric side are not an end 
run around clear federal jurisdiction and that the Commission should 
withdraw its assertion of jurisdiction over the retail transmission 
component of unbundled retail sales.
    VT DPS contends that the Commission's rationale is flawed: ``FERC's 
analysis rests on the same very shaky ground as its similar claim of 
jurisdiction over buy-sell arrangements by local gas distribution 
companies.'' According to VT DPS, all retail transactions are subject 
to state jurisdiction and asks the Commission to clarify that the 
Commission defines buy-sell as it did in the NOPR, but also acknowledge 
that it has no jurisdiction over such arrangements.
    IN Com asserts that in the absence of any record of abusive and 
undermining actions by states under the guise of buy-sell arrangements, 
there is not even a remedial justification to touch buy-sell 
transactions. It contends that a difference between the FPA and the NGA 
warrants different treatment--the FPA exempts from FERC jurisdiction 
local distribution and transmission of electric energy in intrastate 
commerce. By redefining interstate transmission, IN Com claims that the 
Commission proposes to do away with the meaning history has accorded to 
a variety of transactions previously considered wholly intrastate in 
nature. According to IN Com, states should be allowed to experiment 
with and allow different forms of buy-sell transactions as part of the 
evolving marketplace.

Commission Conclusion

    Four parties (PA Com, IL Com, VT DPS and IN Com) have raised 
concerns regarding the Commission's determination that it has 
jurisdiction over the interstate transmission component of transactions 
in which an end user arranges for the purchase of generation from a 
third party. The Commission reiterates that we will have to address 
these situations on a case-by-case basis. We disagree with IL Com that 
States have exclusive authority to regulate the interstate transmission 
component of buy-sell transactions. Similarly, we deny the VT DPS 
request that we acknowledge no jurisdiction over such arrangements. The 
fact remains that these arrangements could be used by parties to 
obfuscate the true transactions taking place and thereby allow parties 
to circumvent Commission regulation of transmission in interstate 
commerce. We reserve our authorities to ensure that public utilities 
and their

[[Page 12372]]

customers are not able to circumvent non-discriminatory transmission in 
interstate commerce. In response to VT DPS' contention that the 
Commission's analysis here rests on the same shaky ground as its 
similar claim of jurisdiction over buy-sell arrangements by local gas 
distribution companies, we note that the D.C. Circuit recently affirmed 
the Commission's assertion of jurisdiction over buy/sell arrangements 
under the Natural Gas Act.<SUP>468
---------------------------------------------------------------------------

    \468\ United Distribution Companies, 88 F.3d at 1154-57.
---------------------------------------------------------------------------

State Jurisdiction Over the Service of Delivering Electric Energy 
to End Users

Rehearing Requests

    IL Com states that it is far from clear what FERC contemplates by 
the ``service'' of delivery of electric energy by a delivering utility 
in the retail wheeling transaction. It is equally unclear to IL Com 
whether the ``service'' to which Order No. 888 refers is a public 
utility activity over which state regulators would have jurisdiction. 
IL Com argues that it is the Illinois legislature, not FERC, that 
determines whether IL Com can regulate something called ``delivery 
service.'' <SUP>469
---------------------------------------------------------------------------

    \469\ See also AK Com (should not create a fictional concept of 
delivery service--the legal reality is that, under retail 
competition, state law will establish a customer's right to be 
served and a generation owner's right to produce power. AK Com 
asserts that the state can then attach conditions to those rights).
---------------------------------------------------------------------------

    MO/KS Coms ask the Commission to clarify the meaning of the 
statement that even when the test for local distribution facilities 
identifies no local distribution facilities, the Commission believes 
that states have authority over the service of delivering electric 
energy to end users. According to MO/KS Coms:

    The authority to shop at retail and to sell at retail do not 
exist in the FPA. If the Commission's goal is to recognize the 
States' authority to establish conditions on retail competition, it 
need only acknowledge the State jurisdiction to establish the 
opportunity to shop and sell at retail. If this is what the 
Commission is seeking to accomplish by its discussion of `delivery 
service,' then we support the Commission.<SUP>470

    \470\ MO/KS Coms at 1-13.
---------------------------------------------------------------------------

    Coalition for Economic Competition asserts that the Commission 
failed to consider that the sale of electric energy may take place 
outside of the state into which the energy is transmitted, and that the 
local regulatory commission may have no jurisdiction over either the 
sale or the transmission of the energy.

Commission Conclusion

    Several parties ask us to clarify our conclusion that even when the 
seven-factor test for local distribution facilities does not identify 
local distribution facilities, we believe states have authority over 
the ``service'' of delivering electric energy to end users. We clarify 
that states have the authority to determine the retail marketing areas 
of electric utilities within their jurisdictions, and the end user 
services that those utilities must provide, but we did not in Order No. 
888 intend to opine on the extent of authority given by state 
legislatures to their state commissions. Rather, our statement 
regarding state authority over the ``service'' of delivering electric 
energy is intended to recognize the historical and local nature of 
delivering power to end users and the states' legitimate concerns and 
responsibilities in regulating local matters.

Deference to States

Rehearing Requests

Support Broader Deference
    NARUC and IL Com argue that the Commission should not simply defer 
to state recommendations concerning the application of the seven-factor 
test or the recovery of stranded costs, but should conclusively rely on 
the findings by state commissions.
    NY Com argues that the Commission should not limit deference to 
instances in which states order retail wheeling, but should defer to 
all state commission recommendations regarding the definition of local 
distribution facilities.
    FL Com asserts that the Rule fails to say where deference will be 
given. It argues that the Rule should state that when a state 
commission has held a proceeding on matters related to the requirements 
of the Rule, the Commission shall give deference to the state 
commission decisions. Moreover, it asserts that the Commission should 
codify the deference standard: ``When a state commission has held a 
proceeding on matters related to the requirements of this rule, the 
Commission shall give deference to the state commission decisions.'' 
(FL Com at 7-9).
    The commitment to defer to a state regulatory commission or agency, 
argues NE Public Power District, should be clarified with respect to 
utilities located in Nebraska, which has no such commission or agency. 
NE Public Power District assumes that deference will be accorded to 
decisions of NE Public Power District's Board of Directors; if not, it 
asks the Commission to clarify.
    PA Com asks the Commission to clarify what a state regulatory 
agency must demonstrate to secure deference and to define the term 
``consult.'' PA Com states that, in discussing the seven indicia, the 
Commission states that it will ``consider'' jurisdictional 
recommendations by states, which PA Com asserts is much different from 
deference. It also asserts that the Commission must clarify what it 
will do if a utility's classifications and/or cost allocations are not 
supported by state regulatory authorities.

Oppose Deference to State Authorities

    TANC argues that the Commission erred in deferring to state 
regulatory authorities in drawing jurisdictional lines for local 
distribution facility classifications and/or cost allocations. 
According to TANC, the Commission unlawfully and unnecessarily 
abdicated its jurisdiction under the FPA (citing New England Power Co. 
v. New Hampshire, 455 U.S. 331, and Nantahala Power and Light Co. v. 
Thornburg, 476 U.S. 953). With respect to ISOs, it asserts that the 
Commission should not defer to state authority in making determinations 
with respect to classifications of facilities.

Commission Conclusion

    In response to NARUC and IL Com's arguments that this Commission 
should not simply defer to state commissions regarding application of 
the seven-factor test but instead should conclusively rely on the 
findings of state commissions, we believe this is inconsistent with the 
case law which states that local distribution it is a matter of fact 
for the Commission to determine as an original matter.<SUP>471 
Additionally, we have an independent obligation to ensure that we are 
fulfilling our responsibilities under the FPA to regulate facilities 
that are used in interstate commerce. We cannot delegate our 
jurisdiction. However, we intend to provide broad deference to states 
in determining what facilities are Commission-jurisdictional 
transmission facilities and what facilities are state-jurisdictional 
local distribution facilities, so long as our comparability principles 
are not compromised and we are able to fulfill our responsibilities 
under the statute.
---------------------------------------------------------------------------

    \471\ See Colton and Connecticut Light and Power, supra.
---------------------------------------------------------------------------

    We reject FL Com's suggestion that we codify the deference 
standard. This is neither necessary nor appropriate. In response to NE 
Public Power District's request that we clarify to whom we would give 
deference in Nebraska, we clarify that because Nebraska does not have 
an electric regulatory commission or agency, there is no appropriate 
regulatory entity to whom our deference standard would apply; 
accordingly, we will address the transmission/local

[[Page 12373]]

distribution issue for Nebraska without giving deference to any 
particular entity. In response to PA Com's request that we clarify what 
we will do if a utility's classifications and/or cost allocation 
proposals are not supported by state regulatory authorities, we will 
make a determination based on the factual record before us in a 
particular case, taking into account the views of the state regulatory 
authority.
    TANC has argued that we have unlawfully abdicated our jurisdiction 
by deferring to state recommendations. TANC confuses delegation of 
jurisdiction, which we cannot do, with willingness to defer to states 
based on their application of criteria that we have provided. Even in 
the cases in which the Commission defers to states' views, we will 
still independently evaluate all material issues and proceed only where 
substantial evidence supports the states' views. The Commission clearly 
can entertain requests for deference in these circumstances.

J. Stranded Costs

    As indicated in our prior discussion in Section IV.A.5, there are 
two major overlapping transition issues that arise as a result of this 
rulemaking: stranded cost recovery and how to deal with contracts 
entered into under the prior regulatory regime. We here address 
stranded cost recovery and, as in the prior discussion, we believe it 
is important to explain the general context in which our stranded cost 
determinations have been made before addressing the various rehearing 
requests on this issue.
    In Order No. 888, the Commission removed the single largest barrier 
to the development of competitive wholesale power markets by requiring 
non-discriminatory open access transmission as a remedy for undue 
discrimination. This action carries with it the regulatory public 
interest responsibility to address the difficult transition issues that 
arise in moving from a monopoly, cost-based electric utility industry 
to an industry that is driven by competition among wholesale power 
suppliers and increasing reliance on market-based generation rates. The 
most critical transition issue that arises as a result of the 
Commission's actions in this rulemaking is how to deal with the 
uneconomic sunk costs that utilities prudently incurred under an 
industry regime that rested on a regulatory framework and a set of 
expectations that are being fundamentally altered.
    The Commission determined in Order No. 888 that it must address 
stranded costs, and that it must do so at an early stage--particularly 
in light of the lessons learned from our experience with similar issues 
in the natural gas area. We noted that when we did a similar 
restructuring in the gas industry, the D.C. Circuit invalidated the 
Commission's efforts precisely because the Commission had failed to 
deal with the stranded cost problem in a satisfactory manner.<SUP>472 
We explained that, based on the lesson of AGD, the Commission cannot 
change the rules of the game without providing a mechanism for recovery 
of the costs caused by such regulatory-mandated change.
---------------------------------------------------------------------------

    \472\ Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. 
Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD).
---------------------------------------------------------------------------

    Since the time Order No. 888 issued, we have been provided with 
additional guidance from the court in the natural gas area, which has 
further helped to inform our decisions here. In its decision on review 
of Order No. 636,<SUP>473 the D.C. Circuit upheld the Commission's 
decision to allow the recovery of gas supply realignment costs. In so 
doing, the court, while questioning a specific feature of the stranded 
cost recovery mechanism employed in Order No. 636, has nevertheless 
again reaffirmed the basic principle that stranded cost recovery is an 
appropriate component of a regulatory policy aimed at accomplishing a 
fair and reasonable transition to competitive markets. The question as 
to the Commission's ability to allow the recovery of stranded costs has 
been laid to rest.
---------------------------------------------------------------------------

    \473\ United Distribution Companies v. FERC, 88 F.3d 1105 (1996) 
(United Distribution Companies).
---------------------------------------------------------------------------

    The task before the Commission in this rulemaking is thus to 
determine how best to meet its responsibility to address the costs of 
the transition to a competitive industry, particularly insofar as those 
costs are stranded, or in effect rendered unrecoverable, as a result of 
the transmission access required by us under the FPA.<SUP>474 As the 
rehearing arguments demonstrate, there is no consensus on how the 
Commission should address the stranded cost issue. In fact, petitioners 
are at polar extremes as to what the Commission should do regarding 
stranded costs. Some argue that the Commission has gone too far in 
permitting utilities to seek recovery of stranded costs, whether such 
costs are associated with wholesale requirements contracts, with 
retail-turned-wholesale customers, or with retail customers that obtain 
retail wheeling.<SUP>475 Others argue that the Commission has not gone 
far enough and that it must broaden the scope of stranded cost recovery 
permitted under the Rule. Indeed, some would have us be the guarantor 
for recovery of all uneconomic costs that might be stranded in the move 
to more competitive markets, no matter how tenuous the nexus to this 
Rule, and irrespective of state-Federal jurisdictional complexities. 
Some support the Commission's decision to recover stranded costs 
directly from the departing customers. Others would prefer that the 
Commission require utilities to absorb a portion of their stranded 
costs or that the Commission spread the burden of stranded costs among 
all of the utility's customers. Some object that the Commission's 
approach to stranded costs in the electric industry is different from 
that adopted in the gas industry. Some entities support the 
Commission's revenues lost approach for measuring a departing 
customer's stranded cost obligation. Others propose different methods 
for computing stranded costs.
---------------------------------------------------------------------------

    \474\ Such access may be the open access required under this 
Rule or case-by-case transmission access ordered pursuant to FPA 
section 211.
    \475\ We note that the regulations implementing this Rule use 
``wholesale stranded cost'' and ``retail stranded cost'' as 
shorthand terms to refer to the different situations in which a 
utility may experience stranded costs. However, as the definitions 
of those terms make clear, it is not the nature of the costs 
(wholesale vs. retail) that is controlling for purposes of stranded 
cost recovery under this Rule. Rather, the controlling factors are 
the status of the customer (wholesale transmission services customer 
vs. retail transmission services customer) with whom the costs are 
associated, and whether the transmission tariffs used by the 
customer to escape its former power supplier (thus causing the 
stranding of costs to occur) were required by this Commission or by 
a state commission. As a result, ``retail stranded costs'' refers to 
stranded costs associated with retail wheeling customers.
---------------------------------------------------------------------------

    Given the plethora of positions that entities have raised both 
initially and on rehearing concerning stranded costs, the Commission 
has taken a careful, measured approach with regard to stranded cost 
recovery. The Commission has balanced a number of important interests 
in order to achieve what it believes will be a fair and orderly 
transition to competitive markets. These interests include the 
financial stability of the electric utility industry, upholding the 
regulatory bargain under which utilities made major capital 
investments, and not shifting costs to customers that had no 
responsibility for causing those costs to be incurred. The Commission 
also has adopted an approach that, for purposes of stranded cost 
recovery from wholesale transmission customers, relies on the nexus 
between stranded costs and the use of transmission tariffs required by 
this Commission and, for purposes of stranded cost recovery from retail 
customers, recognizes state commission

[[Page 12374]]

jurisdiction but fills potential regulatory gaps that could arise in 
the transition to new market structures.
    The balancing of interests and considerations described above is 
reflected in the following central components of the Rule's stranded 
cost provisions, which are reaffirmed herein.<SUP>476 First, the 
Commission has determined that the most reasonable, legally supportable 
approach is one that permits utilities to seek recovery of wholesale 
stranded costs under this Rule (whether the stranded costs are 
associated with a departing wholesale requirements customer or with a 
retail-turned-wholesale customer) only in those cases in which there is 
a direct nexus between the availability and use of Commission-required 
transmission access <SUP>477 and the stranding of costs. In order for 
the utility to be eligible to seek recovery of stranded costs from a 
departing customer, the customer must have obtained access to a new 
generation supplier through the use of the former supplying utility's 
Commission-required transmission tariff (i.e., its open access tariff 
or a tariff ordered pursuant to FPA section 211), not through the use 
of another utility's transmission system.
---------------------------------------------------------------------------

    \476\ We reaffirm below our basic determinations, but make 
certain clarifications on limited issues and grant rehearing on the 
municipal annexation issue.
    \477\ As we explain below, by ``Commission-required transmission 
access'' we mean the open access transmission required under this 
Rule or required pursuant to a section 211 order, as well as 
transmission provided prior to Order No. 888 (and not pursuant to a 
section 211 order) where such transmission was provided on a case-
by-case basis to comply with the Commission's comparability 
requirement. See note 484 infra.
---------------------------------------------------------------------------

    Other cost recovery issues are more appropriately addressed outside 
the context of this Rule. For example, the Rule is not intended to 
apply to costs associated with the normal risks of competition, such as 
self-generation, cogeneration, or loss of load, that do not arise from 
the new, accelerated availability of Commission-required transmission 
access. If a customer leaves its utility supplier by exercising options 
that could have been undertaken prior to mandatory transmission under 
Order No. 888 or the Energy Policy Act, or that do not rely on access 
to the former seller's transmission, there is no direct nexus to 
Commission-required transmission access and thus no opportunity for 
stranded cost recovery under the Rule.
    Second, the Commission has limited the opportunity to seek stranded 
cost recovery under the Rule primarily to two discrete situations: (1) 
Costs associated with customers under wholesale requirements contracts 
executed on or before July 11, 1994 (referred to in the Rule as 
``existing wholesale requirements contracts'') that do not contain an 
exit fee or other explicit stranded cost provision; and (2) costs 
associated with retail-turned-wholesale customers. With regard to the 
existing wholesale requirements contracts, the Commission also has made 
a finding that it is in the public interest to permit amendments to add 
stranded cost provisions to these contracts, even if they contain 
Mobile-Sierra clauses, if case-by-case evidentiary burdens are met. We 
do not interpret the Mobile-Sierra public interest standard as 
practically insurmountable in extraordinary situations such as this one 
where historic statutory and regulatory changes have converged to 
fundamentally change the obligations of utilities and the markets in 
which they and their customers will operate.
    Third, Order No. 888 does not guarantee that a utility will be 
allowed to recover stranded costs. Rather, it provides an opportunity 
for such recovery. To be eligible to recover stranded costs from a 
departing customer in a particular case, the utility must demonstrate 
that it incurred costs to provide service to the customer based on a 
reasonable expectation of continuing service to that customer beyond 
the contract term.<SUP>478 In the case of stranded costs associated 
with wholesale requirements contracts customers, if the contract 
contains a notice of termination provision, that provision is strong 
evidence that the parties were aware that at some point in the future 
the customer might seek to find another supplier. Therefore, there is a 
rebuttable presumption of no reasonable expectation, and therefore no 
opportunity for stranded cost recovery unless the utility can overcome 
the presumption.
---------------------------------------------------------------------------

    \478\ We have made a minor revision to the regulatory text, 
section 35.26(c)(2), to conform the language of that section with 
sections 35.26(b) (1) and (5). A conforming revision has been made 
to section 35.26(d)(2)(i).
---------------------------------------------------------------------------

    The Commission has concluded that direct assignment of stranded 
costs to the departing customer (through either an exit fee or a 
surcharge on transmission) is the appropriate method for recovery of 
stranded costs under the Rule. In reaching this conclusion, the 
Commission carefully weighed the arguments supporting direct assignment 
of stranded costs against those supporting a more broad-based approach, 
such as spreading stranded costs to all transmission users of a 
utility's system, and also took into account the fact that we applied a 
different approach in the natural gas area. The central considerations 
that support a direct assignment approach in the electric industry are 
that the approach follows the traditional regulatory concept of cost 
causation, it avoids shifting costs to customers that had no 
responsibility for causing them to be incurred or for causing them to 
be stranded, and it is still possible to apply such an approach at this 
stage of the industry's evolution.
    There is no question that, without the stranded cost recovery 
mechanism, some customers would be far more likely to switch to lower-
cost suppliers and enjoy sooner the benefits of a competitive power 
market. But, as detailed in Order No. 888, such an approach may result 
in higher costs for other customers. We thus have had to balance the 
potential for earlier benefits for some customers against other public 
interest considerations, most particularly the need to provide a fair 
mechanism by which utilities can recover the costs of past investments 
under traditional regulatory concepts of prudently incurred costs and 
cost causation. The result is not to deny competitive advantages, but 
only to delay their full realization for some customers so that all 
customers ultimately will benefit.
    While Order No. 888's cost causation approach is different from the 
Order No. 636 cost spreading approach that was affirmed in the United 
Distribution Companies case, we believe it is the preferable approach 
given the early stage of the electric utility's competitive transition. 
We do not read the court's opinion as precluding the Commission from 
adopting a direct assignment approach in Order No. 888, particularly 
where, as here, the Commission has fully explained and justified the 
reasons for following traditional cost causation principles. In 
addition, although the United Distribution Companies court remanded for 
further consideration (in light of Order No. 636's cost spreading 
approach) the decision not to require any pipeline absorption of gas 
supply realignment costs, the Commission has fully explained how its 
decision in Order No. 888 not to require any utility absorption of 
stranded costs is consistent with its decision to follow traditional 
cost causation principles. With respect to the fundamental conclusion 
that utilities should be permitted an opportunity to recover their 
prudently incurred costs, Order No. 888 is fully consistent with Order 
No. 636. Although the Commission in Order No. 888 chose a direct 
assignment method (rather than the cost-spreading

[[Page 12375]]

approach in Order No. 636) for purposes of allocating stranded cost 
responsibility among customers, the approach used by the Commission in 
Order No. 888 is not governed by decisions in Order No. 636, but in 
either event the Commission must demonstrate that its choice of methods 
is based on reasoned decision-making.
    In considering the stranded cost issues that may arise in the 
transition to competitive markets, the Commission also has taken 
cognizance of significant changes involving retail customers and the 
stranded cost issues that arise as retail customers convert to 
wholesale customer status (e.g., through municipalizations) in order to 
obtain the open access afforded by Order No. 888, or as they obtain 
retail wheeling required by state commissions. These situations involve 
new and complex jurisdictional issues and represent the bulk of 
potential stranded costs facing the industry. We believe it is 
important to clarify the Commission's decisions as to when it will 
entertain requests for stranded cost recovery in these situations, and 
our reasons for doing so.
    The Commission's determination that it, rather than the states, 
should be the primary forum for addressing stranded costs associated 
with a retail-turned-wholesale customer <SUP>479 is limited to those 
cases in which there is a direct nexus between the availability and use 
of Commission-required transmission access and the stranding of costs. 
We believe we have both the authority and the obligation to provide an 
opportunity for stranded cost recovery in these situations because the 
bundled retail customer would not be able to obtain access to the new 
supplier but for the Commission's order requiring transmission. The 
creation of a new wholesale entity to purchase power on behalf of 
retail customers would not, by itself, trigger stranded costs. In the 
absence of transmission access from the historical supplier of the 
retail customers, the new entity would have to remain on the historical 
supplier's generation system because it would have no way to reach 
other power suppliers, and stranded costs would not occur.<SUP>480 
Therefore, there is a causal nexus between the stranded costs and the 
availability and use of the tariff services required by the 
Commission.<SUP>481 Moreover, because of this causal nexus between the 
use of a jurisdictional utility's Commission-required transmission 
tariff and the potential for foregone revenues by that jurisdictional 
utility as a result of the Commission-required access, the stranded 
costs associated with a retail-turned-wholesale customer are properly 
viewed as economic costs that are jurisdictional to this Commission.
---------------------------------------------------------------------------

    \479\ In Order No. 888 and here, we sometimes use the shorthand 
expression ``retail-turned-wholesale'' customer. By this we do not 
mean that a retail customer who is an ultimate consumer ceases to be 
an ultimate consumer, or that this customer begins to purchase 
electric energy for resale. Rather, in a ``retail-turned-wholesale 
customer'' situation, such as the creation of a municipal utility 
system, a newly-created entity becomes a wholesale power purchaser 
on behalf of retail customers who were formerly bundled customers of 
the historical local utility power supplier. The new municipal 
utility is the conduit by which retail customers, if they cannot 
obtain direct retail access, can reach power suppliers other than 
their historical local utility power supplier. Although the retail 
customers remain bundled retail customers, in that they become the 
bundled customers of the new entity, we call this a ``retail-turned-
wholesale customer'' situation because the new entity in effect 
``stands in the shoes'' of the retail customers for purposes of 
obtaining wholesale transmission access and new power supply.
    \480\ Exceptions would be self-generation or construction by the 
new entity of its own transmission line, in which case, as noted 
earlier, the stranded cost provisions of Order No. 888 would not 
apply because such options have always been available as 
alternatives to purchasing power from the historical supplying 
utility and do not involve the use of the utility's transmission 
facilities under an open access tariff. Thus the departure of 
customers under these circumstances cannot be linked to the open 
access requirements of this Rule.
    \481\ As discussed in greater detail in Sections IV.J.6 and 
IV.J.12 below, we clarify that the opportunity for recovery of 
stranded costs in a retail-turned-wholesale situation is limited to 
cases in which the former bundled retail customer subsequently 
becomes, either directly or through another wholesale transmission 
purchaser, an unbundled wholesale transmission services customer of 
its former supplier. We have revised section 35.26(b)(1)(i) of the 
Commission's regulations accordingly.
---------------------------------------------------------------------------

    In contrast, in the situation in which a bundled retail customer 
obtains retail wheeling, stranded costs are directly caused by the 
availability and use of unbundled retail services required by the state 
commission, not this Commission. <SUP>482 Thus, the Commission believes 
that states, not the Commission, should be the primary forum for costs 
associated with a bundled retail customer that obtains retail wheeling. 
The Commission's decision to entertain requests to recover stranded 
costs caused by retail wheeling in only a limited circumstance (where 
the state regulatory authority does not have authority under state law 
to address stranded costs when the retail wheeling is required) is 
based on a policy decision by this Commission that it will step in to 
fill a regulatory ``gap'' that could result in no effective forum in 
which utilities would have an opportunity to seek recovery of prudently 
incurred costs.
---------------------------------------------------------------------------

    \482\ Unbundled retail transmission services required by a state 
commission could be taken under the same pro forma open access 
tariff used by wholesale customers or, if determined appropriate by 
the Commission, under a separate retail tariff filed at the 
Commission. The critical point, however, is that in either case, the 
unbundled services are required by the state and not by this 
Commission.
---------------------------------------------------------------------------

    Finally, after considering various proposals regarding how stranded 
costs should be calculated, and reviewing the arguments of petitioners 
on rehearing, the Commission continues to believe that the revenues 
lost approach is the fairest and most efficient way to determine the 
amount of stranded cost assigned to a departing customer during the 
transition to a competitive wholesale bulk power market. The Commission 
has rejected an asset-by-asset approach as overly complicated and 
costly.
    We respond below to the specific arguments raised on rehearing and 
elaborate on the above determinations.
1. Justification for Allowing Recovery of Stranded Costs
    In Order No. 888, the Commission concluded that utilities should be 
given the opportunity to seek recovery of legitimate, prudent and 
verifiable stranded costs associated with a limited set of wholesale 
requirements contracts executed on or before July 11, 1994. <SUP>483 We 
stated that utilities that entered into contracts to make wholesale 
requirements sales under an entirely different regulatory regime should 
have an opportunity to recover stranded costs that occur as a result of 
customers leaving the utilities' generation systems through Commission-
jurisdictional open access tariffs or FPA section 211 orders to reach 
other power suppliers. We explained that utilities that made large 
capital expenditures or long-term contractual commitments to buy power 
years ago to supply their customers should not now be held responsible 
for failing to foresee the actions this Commission would take to alter 
the use of their transmission systems in response to the fundamental 
changes that are taking place in the industry. We found that recent 
significant statutory and regulatory changes are central to the 
circumstances that now place at risk the recovery of past investment 
decisions of utilities. We indicated that we will not ignore the 
effects of these changes as we fashion policies that will govern 
possible recovery of these costs in the transition to an open access 
regulatory regime.
---------------------------------------------------------------------------

    \483\ FERC Stats. & Regs. at 31,788-91; mimeo at 451-58.
---------------------------------------------------------------------------

    We stated that while there has always been some risk that a utility 
would lose a particular customer, in the past that risk was smaller. It 
was not

[[Page 12376]]

unreasonable for the utility to plan to continue serving the needs of 
its wholesale requirements customers and retail customers, and for 
those customers to expect the utility to plan to meet their future 
needs. We concluded that with the new open access transmission, 
<SUP>484 the risk of losing a customer is radically increased. If a 
former wholesale requirements customer or a former retail customer uses 
the new open access to reach a new supplier, the utility is entitled to 
seek recovery of legitimate, prudent and verifiable costs that it 
incurred under the prior regulatory regime to serve that customer. The 
utility, however, would have the burden of demonstrating that it had a 
reasonable expectation of continuing to serve the departing customer.
---------------------------------------------------------------------------

    \484\ In Order No. 888, we explained that by ``new open access'' 
or ``open access transmission'' we were referring to Commission-
jurisdictional open access tariffs or to a tariff ordered pursuant 
to FPA section 211. Although we generally refer in the text of Order 
No. 888 and the text of this order to the open access tariffs 
required under this Rule and to tariffs required pursuant to a 
section 211 order, we clarify that the ``new open access'' or ``open 
access transmission'' described in this Rule also includes 
transmission provided prior to Order No. 888 (and not pursuant to a 
section 211 order) where such tariff filings were made on a case-by-
case basis to comply with the Commission's comparability 
requirement. To avoid any confusion on this point, we refer in this 
order to all such open access transmission as ``Commission-mandated 
transmission access'' or ``Commission-required transmission 
access.''
---------------------------------------------------------------------------

Rehearing Requests Opposing, or Seeking Limitations on, Stranded Cost 
Recovery

    Several entities challenge the Commission's decision to give 
utilities an opportunity to recover legitimate, prudent and verifiable 
stranded costs. NASUCA argues that the transition to wholesale 
competition was underway before and apart from the NOPR. It asserts 
that the drivers of the developing competition include voluntary open 
access filings by utilities seeking mergers or market-based rate 
authority and section 211 of the FPA, as amended by the Energy Policy 
Act of 1992 (Energy Policy Act). According to NASUCA, stranded 
investment results from legislative, not regulatory action, and the 
stranded cost issue does, and would, exist without the Open Access 
Rule. It contends that an acceleration of the competitive wholesale 
transformation does not change its nature or origins. NASUCA also 
contends that the issuance of the Open Access Rule does not justify 
stranded cost recovery on ``regulatory compact'' grounds because it is 
not a fundamental change.
    Other entities object that there is no basis for the Commission to 
impute an extra-contractual obligation to serve wholesale requirements 
customers.<SUP>485 These entities argue, for example, that utilities 
could and should have protected themselves from any potential stranded 
costs through individual customer contracts.
---------------------------------------------------------------------------

    \485\ E.g., American Forest & Paper, Blue Ridge, TDU Systems, IN 
Consumer Counselor, IN Consumers, IL Com.
---------------------------------------------------------------------------

    IN Consumer Counselor and IN Consumers object that Order No. 888 
attempts to transform the obligation to provide a utility with an 
``opportunity'' for a fair return when prices are regulated into an 
``entitlement'' to ``recover legitimate, prudent and verifiable costs 
that it incurred under the prior regulatory regime.'' <SUP>486
---------------------------------------------------------------------------

    \486\ IN Consumer Counselor at 9 (citing Order No. 888, mimeo at 
452-53); IN Consumers at 10 (same).
---------------------------------------------------------------------------

    Several entities submit that the Commission has not adequately 
addressed the potential anticompetitive impact of stranded cost 
recovery.<SUP>487 Some argue that giving utilities the opportunity to 
recover wholesale stranded costs will delay the opportunity for 
historically captive customers to benefit from competitive 
alternatives.<SUP>488 Central Illinois Light contends that the Rule is 
arbitrary and capricious because it will have different impacts on 
different customers, which Central Illinois Light asserts will be due 
to accidents of circumstance rather than the conscious application of 
rational policy choices. IN Consumers objects that two similarly-
situated customers of the utility for identical transmission services 
will be required to pay substantially different rates for the same 
service (where one previously purchased its power requirements from the 
utility, while the other used an alternate source of supply).
---------------------------------------------------------------------------

    \487\ E.g., APPA, IN Consumer Counselor, IN Consumers, Suffolk 
County, TDU Systems, Specialty Steel, Occidental Chemical, Central 
Illinois Light, American Forest & Paper, Nucor, Blue Ridge.
    \488\ E.g., APPA, IN Consumer Counselor, IN Consumers, Suffolk 
County, TDU Systems, Specialty Steel.
---------------------------------------------------------------------------

    Central Illinois Light also objects that even a partial allowance 
of stranded costs will likely encourage predatory pricing. It says that 
the Commission has failed to adequately address the harm that stranded 
cost ``subsidies'' pose to low-cost utilities with little or no 
stranded costs. Others contend that the Rule would subvert economic 
efficiency by unjustly enriching utilities that have not attempted to 
meet the new market demands, to the detriment of those utilities that 
have.<SUP>489 According to Occidental Chemical, the Commission has made 
no finding that the pro-competitive goals of Order No. 888 can be 
accomplished in light of the costs and uncertainties presented by 
stranded cost recovery.
---------------------------------------------------------------------------

    \489\ E.g., American Forest & Paper, Nucor, Blue Ridge.
---------------------------------------------------------------------------

    Several entities also challenge the adequacy of the factual record 
for allowing wholesale stranded cost recovery and argue that utilities 
have not provided the hard data on wholesale stranded costs that the 
Commission needs to justify Order No. 888.<SUP>490 Central Illinois 
Light objects that the Commission failed to note or to discuss data 
presented by commenters showing that only a small group of high-cost 
utilities need some stranded cost protection. American Forest & Paper 
argues that the Commission has failed to demonstrate on the record the 
existence of any stranded wholesale investment that was or could be 
caused by the transition to open access transmission.
---------------------------------------------------------------------------

    \490\ E.g., ELCON, TDU Systems, Central Illinois Light, American 
Forest & Paper.
---------------------------------------------------------------------------

    SC Public Service Authority repeats its earlier request that the 
Commission deny market-based rate authority to any utility that elects 
to recover stranded costs from departing customers.<SUP>491 It objects 
that the Commission failed to specifically respond to its previous 
comments on this issue.
---------------------------------------------------------------------------

    \491\ See also American Forest & Paper (unless a utility agrees 
not to seek stranded costs under the Rule, the utility should not be 
found to have mitigated its transmission market power for purposes 
of charging market-based rates, merging with other utilities or 
otherwise, simply by filing an open access tariff).
---------------------------------------------------------------------------

    American Forest & Paper objects that utilities that voluntarily 
filed open access tariffs cannot use the stranded cost rule because 
their loss of customers cannot be said to have occurred only because of 
the Rule. It submits that only those utilities who had to be forced to 
offer open access transmission are being rewarded.
    San Francisco asks that the Commission include ``exercise of pre-
existing contract rights for transmission and designation of wholesale 
loads'' or similar language as one of the examples (listed in footnote 
718) of situations for which stranded costs may not be sought. San 
Francisco explains that it wants to ensure that PG&E would not have any 
basis to argue that any load loss PG&E suffers as a result of San 
Francisco's designation of municipal loads would be eligible for 
stranded cost recovery.

Commission Conclusion

    We will deny the requests for rehearing of our decision to allow

[[Page 12377]]

utilities an opportunity to seek recovery of legitimate, prudent, and 
verifiable stranded costs. As we indicated in Order No. 888, we learned 
from our experience with natural gas that, as both a legal and a policy 
matter, we cannot ignore these costs. The U.S. Court of Appeals for the 
District of Columbia Circuit invalidated the Commission's first open 
access rule for gas pipelines because the Commission failed to deal 
with the uneconomic take-or-pay situation that many pipelines faced as 
a result of regulatory changes beyond their control.<SUP>492 That same 
court has subsequently affirmed the Commission's decision to allow the 
recovery of costs that are stranded in the transition to a competitive 
natural gas industry, most recently by upholding the Commission's 
decision in Order No. 636 to allow the recovery of gas supply 
realignment costs.<SUP>493
---------------------------------------------------------------------------

    \492\ AGD, 824 F.2d at 1021.
    \493\ United Distribution Companies, 88 F.3d 1105 (1996). 
Although the court remanded that aspect of Order No. 636 that allows 
pipelines to recover 100 percent of their gas supply realignment 
costs without requiring any pipeline absorption, we explain in 
Section IV.J.3 below how Order No. 888 is fully consistent with that 
remand.
---------------------------------------------------------------------------

    Here we are faced, once again, with an industry transition in which 
there is the possibility that, as a result of statutory and regulatory 
changes beyond their control, certain utilities may be left with large 
unrecoverable, legitimate and prudent costs or that those costs will be 
unfairly shifted to other (remaining) customers. Thus, in order to 
satisfy our regulatory responsibilities, we must directly and timely 
address the costs of the transition by allowing utilities to seek 
recovery of legitimate, prudent and verifiable stranded costs.<SUP>494 
While the transition to wholesale competition may have begun before the 
NOPR, we strongly disagree with NASUCA's claim that the Open Access 
Rule does not justify stranded cost recovery because an acceleration of 
the transition does not change its nature or origins. The driving force 
behind the development of wholesale competitive markets is the 
widespread transmission access made available through Commission-
mandated transmission tariffs,<SUP>495 including transmission tariffs 
ordered pursuant to FPA section 211 and the transmission tariffs 
required by the Commission's Open Access Rule.<SUP>496 Furthermore, as 
explained in the Rule and as further discussed below, it is the ability 
of customers to obtain readily available Commission-mandated 
transmission access that significantly increases the potential for 
wholesale stranded costs.
---------------------------------------------------------------------------

    \494\ See FERC Stats. & Regs. at 31,789; mimeo at 453-54.
    \495\ As we explain above, Commission-mandated transmission 
tariffs is meant to include all open access tariffs filed pursuant 
to Commission order, including tariffs filed under this Rule, 
tariffs ordered pursuant to FPA section 211, and tariffs that were 
filed on a case-by-case basis to comply with the Commission's 
comparability requirement.
    \496\ As a result of the Open Access Rule, 47 Group 2 public 
utilities, which had no open access transmission tariff available 
prior to Order No. 888, submitted and had available on July 9, 1996 
non-discriminatory open access transmission tariffs. In addition, 
101 Group 1 public utilities, which had some version of open access 
available prior to Order No. 888, filed new open access tariffs 
effective July 9, 1996 in order to conform to the terms and 
conditions of non-discriminatory open access service specified in 
the pro forma tariff. Thus, as of July 9, 1996, 148 of the 166 
public utilities had filed Order No. 888 open access tariffs. At 
least ten others filed open access tariffs after July 9, 1996 (e.g., 
after the Commission dealt with their waiver requests). This, in the 
Commission's view, represents an unprecedented acceleration of the 
transition to competitive bulk power markets. From the issuance of 
the Open Access NOPR in March 1995 until the effective date of Order 
No. 888 on July 9, 1996 is only a little more than one year.
---------------------------------------------------------------------------

    Order No. 888 requires the functional unbundling of a public 
utility's wholesale services. Under the Rule, all public utilities that 
own, control or operate facilities used for transmitting electric 
energy in interstate commerce were required by July 9, 1996 to file 
open access transmission tariffs that contain minimum terms and 
conditions of non-discriminatory service (or to seek waiver), and to 
take transmission service (including ancillary services) for their own 
new wholesale sales and purchases of electric energy under the open 
access tariffs. As a result of Order No. 888, wholesale requirements 
customers that previously were captive customers of their public 
utility suppliers (i.e., they had no choice but to take bundled sales 
and transmission services from their suppliers) will be able at the 
expiration of their contracts to take unbundled transmission service 
(i.e., transmission-only service) from their former suppliers in order 
to reach new suppliers. While in the past there has been some risk of 
stranded costs due to customers ``leaving'' a supplier's system through 
self-generation or perhaps municipalization, there was little or no 
ability to shop for alternative power such as that which will occur as 
a result of readily available Commission-mandated transmission access. 
Contrary to NASUCA's claims, Order No. 888, coupled with section 211 of 
the FPA, creates the opportunity, as a matter of law, for an existing 
wholesale requirements customer to use the transmission owner's 
facilities to reach a new supplier.<SUP>497 This leaves the former 
supplying utility with significant risk that it will be unable to 
recover costs that the utility incurred based on a reasonable 
expectation that it would continue to serve the departing customer.
---------------------------------------------------------------------------

    \497\ NASUCA and other petitioners offer no persuasive evidence 
that meaningful competition took root prior to the availability of 
the new transmission access requirements. The few utilities that did 
provide transmission service under open access tariffs prior to the 
announcement of the Commission's comparability requirement did not 
offer third parties comparable service. To the contrary, such 
tariffs contained numerous disparities in the transmission service 
that the utilities provided to third parties in comparison to their 
own uses of the transmission system. See, e.g., Entergy Services, 
Inc., 58 FERC para. 61,234, order on reh'g, 60 FERC para. 61,168 
(1992), remanded, sub nom., Cajun Electric Power Cooperative, Inc. 
v. FERC, 28 F.3d 173, 179-80 (D.C. Cir. 1994) (tariff contained 
limitations on point-to-point service and did not provide network 
service; tariff reserved transmission provider's right to cancel 
service in certain instances, even where a customer had paid for 
transmission system modifications). While the desire of customers 
for competitive power markets may have preceded Commission-mandated 
open access, customers had no assurance they could reach alternative 
suppliers until the Commission required utilities to provide 
transmission service on a comparable basis.
---------------------------------------------------------------------------

    Thus, the regulatory and statutory changes contained in Order No. 
888 and in amended section 211, which will act in tandem to provide the 
transmission access necessary to develop the competitive wholesale 
markets envisioned by Congress in the Energy Policy Act, have a direct 
nexus to the potential for wholesale stranded costs. This nexus makes 
it critical that the Commission address this transition issue 
responsibly and equitably. Having balanced the goals of competition, 
the nexus between potential stranded costs and transmission access, and 
the regulatory bargain under which utilities invested billions of 
dollars in reliance on the prior regulatory regime, we believe that 
utilities are entitled to an opportunity to seek recovery of stranded 
costs and that our actions in Order No. 888 are not only legally 
supportable, but also represent sound public policy.
    In response to those entities who argue that there is no basis for 
imputing an extra-contractual obligation to serve wholesale 
requirements customers, as we explained in Order No. 888, we believe 
there previously has been an implicit obligation to serve at wholesale 
in many cases. Such obligation is based, in large part, on the 
recognition that historically most wholesale requirements customers 
were captive and had no means of reaching alternative suppliers. The 
local utility supplied bundled generation and transmission services to 
these customers on the assumption that they would remain as customers. 
Accordingly, the utility had a concomitant obligation to plan to supply 
these customers'

[[Page 12378]]

continuing needs, and planned its system taking account of the 
wholesale load. In many cases the wholesale customers participated by 
supplying load forecasts. Consistent with this practical obligation to 
serve, the Commission viewed the supplying utility as the supplier of 
first resort, and did not allow a utility to terminate service without 
prior Commission approval. Before Order No. 888, the Commission's 
regulations required prior notification and approval of the proposed 
cancellation or termination of a wholesale requirements contract. We 
note that although Order No. 888 eliminates the prior notice of 
cancellation or termination requirement for power sales contracts 
executed on or after July 9, 1996 (the effective date of the Open 
Access Rule) that are to terminate by their own terms,<SUP>498 it 
expressly retains the prior notice of cancellation or termination 
requirement for any power sales contract executed before that date.
---------------------------------------------------------------------------

    \498\ The Rule requires that the utility notify the Commission 
of the date of termination for this class of contracts within 30 
days after the termination takes place. The Rule retains the prior 
notice of cancellation or termination requirement for power sales 
contracts executed on or after July 9, 1996 if termination is on 
grounds other than expiration of the contract by its terms at the 
end of the contract. See Portland General Electric Company, 75 FERC 
para. 61,310, reh'g denied 77 FERC para. 61,171 (1996) (Commission 
authorization required for termination of power sales contract in 
the event of the commencement of a bankruptcy proceeding, failure to 
perform any obligation under the contract, or failure to provide 
adequate assurance of the ability to perform).
---------------------------------------------------------------------------

    It is important to note, however, that while the stranded cost 
recovery provisions of the Rule are based on the implicit obligation to 
serve, the Rule does not guarantee any extra-contractual wholesale 
stranded cost recovery, much less across-the-board recovery of such 
costs by all public utilities. To the contrary, it provides an 
opportunity for such recovery only for a discrete set of requirements 
contracts (those executed on or before July 11, 1994 that do not 
contain an exit fee or other explicit stranded cost provision), and the 
Rule requires that a utility must meet a heavy burden of proving 
eligibility to recover costs in a particular case: before a departing 
customer is required to pay a stranded cost exit fee or transmission 
surcharge, the utility must demonstrate that it incurred costs to 
provide service to a customer based on a reasonable expectation of 
continuing service to that customer beyond the end of the 
contract.<SUP>499
---------------------------------------------------------------------------

    \499\ To the extent there is any misunderstanding, we clarify 
that the intent of the Rule to permit the ``opportunity'' to recover 
stranded costs is not an ``entitlement'' to recover such costs. As a 
result, the passage in Order No. 888 to which IN Consumer Counselor 
and IN Consumers object (FERC Stats. & Regs. at 31,789, mimeo at 
452-53) should read ``we believe that the utility is entitled to an 
opportunity to recover legitimate, prudent and verifiable costs that 
it incurred under the prior regulatory regime to serve that 
customer'' (emphasis to show added language).
---------------------------------------------------------------------------

    We believe that we adequately address in both Order No. 888 and in 
Section IV.J.2 below the concerns various entities have expressed as to 
the potential anticompetitive impact of stranded cost recovery. 
Although we recognize that stranded cost recovery may delay some of the 
benefits of competitive bulk power markets for some customers, we 
believe that customers as a whole will benefit from a fair and orderly 
transition. Indeed, we are particularly concerned that the failure to 
assign stranded cost responsibilities to customers that have access to 
alternative suppliers will leave captive customers exposed to the risk 
of greater cost burdens, thereby shifting to captive customers the 
costs that were originally incurred for the benefit of the (typically 
larger) customers who have the flexibility to take early advantage of 
competing power suppliers. Avoiding this potential cost shifting 
problem is an important goal of our decision to address the stranded 
cost problem as part and parcel of the decision to mandate open access. 
As we said in Order No. 888:

such transition costs must nevertheless be addressed at an early 
stage if we are to fulfill our regulatory responsibilities in moving 
to competitive markets. The stranded cost recovery mechanism that we 
direct here is a necessary step to achieve pro-competitive results. 
In the long term, the Commission's Rule will result in more 
competitive prices and lower rates for consumers.<SUP>[500]

    \500\ FERC Stats. & Regs. at 31,794; mimeo at 468-69.
---------------------------------------------------------------------------

    We do not believe that allowing utilities an opportunity to seek 
stranded cost recovery will prevent us from achieving the pro-
competitive goals of Order No. 888. To the contrary, as discussed below 
in Section IV.J.3, we think that it is necessary to provide utilities 
the opportunity to seek to recover stranded costs if we are to have a 
fair and orderly transition to more competitive bulk power markets. The 
opponents of Order No. 888's stranded cost approach argue that the 
transition to fully competitive bulk power markets will be slower if we 
allow utilities an opportunity to seek to recover stranded costs from 
departing customers, and with respect to some customers that may well 
be true. As noted earlier, some customers because of their size and 
limited contractual obligations with their current utility suppliers 
have the ability immediately to leave the system. If they are allowed 
to do so without paying the costs incurred to provide them expected 
future service, the economic attractiveness of departing the system is 
obviously enhanced and the benefits of competition, for these 
customers, obviously come sooner rather than later. However, the pace 
at which fully competitive markets are achieved, while important, is 
not the only consideration. It is the Commission's responsibility to 
ensure that the costs of open access are fairly assigned and that the 
benefits of Order No. 888's open access requirements will be fairly 
available to all customers. These dual goals compel us toward a 
balanced approach that, although perhaps delaying somewhat the benefits 
of competition, nevertheless ensures that all customers will share in 
those benefits without undermining historic principles of cost recovery 
upon which utilities were entitled to rely in planning their systems.
    Moreover, as we explain in Section IV.J.3 below, we have carefully 
examined different methods of allocating stranded costs that are found 
to be properly recoverable, including assigning the costs directly to 
the departing customer or spreading the costs to all transmission users 
of a utility's system. We recognize that the direct assignment approach 
to stranded cost recovery delays competition for some customers because 
it attaches a price tag for customers who have the immediate ability to 
leave the system. However, we have identified the advantages and 
disadvantages of each approach and have concluded, on balance, that 
direct assignment is the preferable approach for both legal and policy 
reasons.
    In response to the concerns of some entities that stranded cost 
``subsidies'' may harm low-cost utilities with little or no stranded 
costs, or otherwise may unjustly enrich utilities that have not 
attempted to meet the new market demands to the detriment of those that 
have, we again emphasize the limited and transitional nature of the 
stranded cost recovery opportunity allowed under Order No. 888.<SUP>501 
It is clearly not the Commission's intent that utilities with little or 
no stranded cost exposure be competitively disadvantaged by the Open 
Access Rule. Those utilities with little or no stranded costs will be 
similarly situated with other new suppliers in the sense that they will 
all

[[Page 12379]]

face the potential of not being able to compete immediately for certain 
wholesale customers who are determined to have an obligation to pay 
stranded costs. These customers may find it to be uneconomic to shop 
from new power suppliers because they may have to pay costs they caused 
to be incurred under the prior industry regime before they are able to 
switch suppliers. However, this will be during a transition period 
only, and only with respect to a discrete set of contracts and only 
where the utility meets its burden of proof with respect to a 
particular departing customer.
---------------------------------------------------------------------------

    \501\ As we indicate in Section IV.J.9 below, we disagree that 
the Rule's definition of stranded costs artificially and 
unjustifiably improves the competitive position of an inefficient 
utility.
---------------------------------------------------------------------------

    We reject as misplaced IN Consumers' argument that the Open Access 
Rule is discriminatory because two ``similarly-situated'' customers for 
``identical'' transmission services (one who previously purchased 
transmission bundled with its power requirements from the utility and 
now seeks to purchase only unbundled transmission, and the other who 
previously used an alternative source of supply and seeks to purchase 
unbundled transmission from the utility) will pay substantially 
different rates for the same service. The error in this argument is 
that the two customers in the example are not ``similarly-situated'' 
precisely because one of them was a former bundled wholesale 
requirements customer of the utility for whom the utility may have 
incurred costs to meet reasonably expected customer demand, whereas the 
other was never a generation customer of the utility and thus 
appropriately bears no cost responsibility for stranded generation 
costs incurred by that utility. Indeed, this example illustrates 
precisely the reason underlying the Commission's stranded cost 
mechanism. If a utility had previously served a customer as a seller of 
generation as well as a transmitter, it is allowed an opportunity to 
show that it incurred costs based on a reasonable expectation of 
continuing to serve the power needs of that customer beyond the 
contract term. Similarly, contrary to Central Illinois Light's claim, 
if different treatment of different customers were to occur, it would 
not be due to ``accidents of circumstance''--it would be the result of 
the conscious application by the Commission of its decision to give a 
utility the opportunity to recover stranded costs from a wholesale 
requirements customer if the utility can demonstrate that it incurred 
costs to provide service to the customer based on a reasonable 
expectation that it would continue to serve the customer after the 
contract term.
    In response to the claims of those entities that challenge the 
factual record for allowing wholesale stranded cost recovery, we 
believe that the record in this proceeding clearly demonstrates the 
need to give utilities the opportunity to recover wholesale stranded 
costs. We have shown that the Rule's open access requirement will 
significantly alter historical relationships among traditional 
utilities and their customers. Indeed, that is one of its objectives. 
In the longer term, we seek to have all power supply arrangements 
priced by the competitive marketplace. However, utilities prudently 
incurred costs under a prior regulatory regime that created an 
expectation of an opportunity for recovery of those costs. Common sense 
indicates that a utility that historically supplied bundled generation 
and transmission services to a wholesale requirements customer and that 
reasonably expected to continue to serve the customer may have incurred 
costs to provide service to that customer that could be stranded if the 
customer uses open access transmission to reach a new generation 
supplier.<SUP>502 As we learned from our experience in restructuring of 
the natural gas industry, open access and unbundling did in fact 
exacerbate the take-or-pay problems in the gas industry because it gave 
customers more options. That is what we are doing in the electric 
industry as well. As a result, we have concluded that utilities should 
be permitted to seek recovery of stranded costs in certain limited and 
defined circumstances.
---------------------------------------------------------------------------

    \502\ As the AGD court noted: ``Agencies do not need to conduct 
experiments in order to rely on the prediction that an unsupported 
stone will fall.'' 824 F.2d at 1008.
---------------------------------------------------------------------------

    We disagree with those entities that argue that utilities have not 
provided sufficient data on the existence of wholesale stranded costs 
to justify the approach adopted by the Commission in Order No. 888. 
Presumably these entities would require us to calculate specific 
stranded cost estimates for every public utility before we could act to 
address this critical issue. However, where the Commission decides to 
act by means of a generic rule,<SUP>503 the Commission is not required 
to make individual findings on a utility-by-utility basis.<SUP>504 
Moreover, the Rule does not say that all utilities with wholesale 
contract customers will be allowed to recover stranded costs, only that 
those utilities that have requirements contracts that were executed on 
or before July 11, 1994 that do not contain an exit fee or explicit 
stranded cost provision and that can meet the required evidentiary 
showing would be allowed such recovery. On this basis, our decision to 
give utilities the opportunity to seek stranded cost recovery for 
certain wholesale requirements contracts is not dependent on a showing 
that any particular utility will actually be eligible to recover 
stranded costs as a result of the open access requirement.<SUP>505
---------------------------------------------------------------------------

    \503\ As we noted in Order No. 888, there is no question that it 
is within the Commission's discretion to decide whether to act 
through rule or through case-by-case adjudication. FERC Stats. & 
Regs. at 31,679; mimeo at 127-28.
    \504\ See AGD, 824 F.2d at 1008.
    \505\ Indeed, we are somewhat puzzled by the argument that we 
may not act in the absence of ``hard data'' that the potential 
stranded cost problem is widespread and huge. Here we provide only 
the opportunity to seek stranded cost recovery for a concededly 
narrow subset of cases that we believe may give rise to a valid 
claim for extracontractual recovery. If as petitioners suggest the 
problem is modest and confined to a small number of utilities, the 
evidentiary process will sort that out, and the potential effect on 
departing customers and on the pace of competition will be similarly 
modest.
---------------------------------------------------------------------------

    We also will reject SC Public Service Authority's request that the 
Commission deny market-based rate authority for all utilities seeking 
stranded cost recovery. SC Public Service Authority has failed to 
demonstrate that the ability to seek stranded cost recovery would, by 
definition, eliminate the potential for mitigation of any generation or 
transmission market power. If an entity believes that a utility seeking 
market-based rate authority does not satisfy the Commission's criteria 
for the grant of market-rate authority (e.g., because the utility has, 
or has failed to mitigate, market power in generation or transmission), 
that entity will have ample opportunity to present its case in the 
market-based rate proceeding.
    American Forest & Paper's objection that utilities that voluntarily 
filed open access tariffs cannot utilize the stranded cost provisions 
and therefore that only utilities who were forced to offer open access 
transmission are being rewarded is misplaced. First, there is nothing 
in Order No. 888 that prohibits a utility that voluntarily filed an 
open access transmission tariff from seeking recovery of stranded costs 
if it can demonstrate a reasonable expectation of continuing to serve a 
particular wholesale customer beyond the term of its existing contract. 
Second, many of the ``open access'' tariffs accepted prior to Order No. 
888, while an improvement upon the status quo of no access, did not 
contain the minimum terms and conditions of non-discriminatory service, 
including functional unbundling. Order No. 888 required utilities that 
tendered for filing open access tariffs prior to the issuance of the 
Rule (Group 1 public utilities) to make section 206 compliance filings 
that

[[Page 12380]]

contain the non-rate terms and conditions set forth in the Open Access 
Rule pro forma tariff. That tariff expressly includes provisions 
allowing a transmission provider to seek to recover stranded costs in 
accordance with the terms, conditions and procedures set forth in Order 
No. 888. Of the 101 public utilities that had some version of open 
access available prior to Order No. 888, all now have open access 
tariffs on file that contain provisions that expressly allow the 
transmission provider to seek to recover stranded costs as provided in 
Order No. 888.
    We also will decline San Francisco's request that the Commission 
include ``exercise of pre-existing contract rights for transmission and 
designation of wholesale loads'' or similar language as an example of a 
situation for which stranded costs may not be sought.<SUP>506 We are 
not prepared to make individual factual determinations in the context 
of this Rule.<SUP>507 As specific requests for stranded cost recovery 
are presented to the Commission, they will be addressed based on the 
facts presented and the merits of the particular request.
---------------------------------------------------------------------------

    \506\ In making this determination we do not decide whether such 
situations demonstrate the presence or lack of a reasonable 
expectation of continuing to serve a customer after the expiration 
of an existing wholesale requirements contract (i.e., one that was 
executed on or before July 11, 1994).
    \507\ San Francisco will have sufficient opportunity to raise 
the argument in any PG&E stranded cost recovery case.
---------------------------------------------------------------------------

Rehearing Requests Seeking Broader Stranded Cost Recovery

    In sharp contrast to the entities seeking rehearing of the 
Commission's decision to allow stranded cost recovery, other entities 
ask the Commission to expand the scope of the stranded cost recovery 
allowed by Order No. 888. Various entities ask that the scope of 
stranded cost recovery be expanded to include situations in which the 
departing customer does not take unbundled transmission from the former 
supplier and in which previously existing municipal utilities annex 
additional territory or otherwise expand.<SUP>508 These entities 
disagree with the Commission's analysis in Order No. 888 that the 
opportunity to seek recovery should be precluded in situations in which 
the departing wholesale customer ceases to purchase power from the 
utility but does not use the utility's transmission system to reach 
another supplier. The Commission excluded these situations because the 
costs would not be stranded as a result of the Commission's open access 
transmission requirement, but rather as a result of the exercise of a 
preexisting competitive option. The entities argue on rehearing that 
such costs are attributable to the Commission's efforts to restructure 
the wholesale power market. Several argue that there is no good policy 
reason for addressing stranded costs only where linked directly to the 
Open Access Rule or section 211 orders because a variety of federal 
actions, not just the Open Access Rule and section 211 orders, have 
created a competitive wholesale power market and the specter of 
stranded costs caused by customers departing their traditional utility. 
They contend that, but for the Commission's creation of a vibrant power 
market, EPAct, and other pre-Order No. 888 efforts by the Commission to 
expand transmission access, the preexisting options would not have been 
(and historically were not) exercised.
---------------------------------------------------------------------------

    \508\ E.g., EEI, Coalition for Economic Competition, Puget, 
Centerior, Southern. The issue of expanding the rule to encompass 
municipal annexations and expansions is discussed in greater detail 
in section IV.J.6 below.
---------------------------------------------------------------------------

    Puget argues that even when a departing customer can import its new 
power supply without using its former supplier's transmission system, 
it frequently will be the case that the power supply would not be 
available to the customer if open access transmission rules were not in 
place to permit that power to move from distant generators over 
intervening utilities' transmission facilities.<SUP>509
---------------------------------------------------------------------------

    \509\ Puget submits that the potential for customers not taking 
unbundled transmission services from their former suppliers is 
particularly acute in the Pacific Northwest due to BPA's ownership 
of much of the region's transmission facilities.
---------------------------------------------------------------------------

    EEI expresses concern that strict application of the ``but for open 
access'' test would create new incentives to evade stranded cost 
recovery.<SUP>510 According to EEI, the Rule would deny recovery for 
costs stranded pursuant to a voluntarily negotiated transmission 
service agreement, but would permit recovery if such agreement were 
ordered pursuant to FPA section 211. In this manner, EEI contends that 
the Rule will discourage parties from settling transmission disputes. 
It says that any transmission agreement negotiated under ``the threat'' 
of section 211 should be entitled to stranded cost recovery if 
providing service results in the stranding of legitimate and prudent 
costs.
---------------------------------------------------------------------------

    \510\ NIMO contends that the Commission erred by failing to 
address the extent to which Order No. 888's exceptions to the 
general policy of full stranded cost recovery (e.g., no recovery for 
customer use of new transmission provider or municipal annexations) 
create an opportunity for customers to avoid payment of part or all 
of their share of utility stranded costs, will enable customers to 
take advantage of such opportunities in ways that will reduce rather 
than enhance overall economic efficiency, and will deprive utilities 
of a reasonable opportunity to recover their prudently incurred 
costs or will shift costs unfairly among customers. See also Puget.
---------------------------------------------------------------------------

    PSE&G and Carolina P&L express concern that denying stranded cost 
recovery where the departing customer does not use the former 
supplier's transmission system will create an artificial incentive to 
build ``contract path'' lines designed to thwart stranded cost 
recovery. They maintain that the existence of alternative transmission 
paths should not be a bar to stranded cost recovery where the departing 
customer avails itself of the Commission's Mobile-Sierra finding 
permitting customers to challenge the terms of their contracts under 
the just and reasonable standard. They assert that, notwithstanding the 
availability of alternative transmission, the only way that the 
customer could have availed itself of the Mobile-Sierra finding was as 
a result of the Commission's Open Access Rule.
    Several entities contend that the FPA's requirement of just and 
reasonable rates and the Fifth Amendment's requirement to avoid 
confiscation require the Commission to address stranded costs that 
result when a departing customer does not use the former supplier's 
transmission system or that result from municipal annexation.<SUP>511 
According to Puget, the ultimate Constitutional test will be whether 
Order No. 888 will afford a fair overall return on all prudent utility 
investments under the Constitutional standards set forth by the Supreme 
Court.<SUP>512 Coalition for Economic Competition submits that, as was 
the case in the context of the unbundling of natural gas pipelines, the 
Commission cannot ignore stranded costs resulting from the unbundling 
of electric services and should acknowledge its Constitutional 
obligations to address the recovery of all stranded costs, including 
those that result from municipal expansion and those that result when a

[[Page 12381]]

customer does not obtain transmission services from its former 
supplier.
---------------------------------------------------------------------------

    \511\ E.g., Puget, Coalition for Economic Competition, NIMO. 
These parties make a similar argument in the case of stranded costs 
that result from retail wheeling. See section IV.J.7 below.
    \512\ Puget cites in support Stone v. Farmers' Loan & Trust 
Company, 116 U.S. 307, 331 (1886); Federal Power Commission v. Hope 
Natural Gas Company, 320 U.S. 591, 602 (1944); and Duquesne Light 
Company v. Barasch, 488 U.S 299, 307-08 (1989). Puget objects that 
the stranded cost recovery mechanism in Order No. 888 is too narrow 
and too easy to circumvent; it can be denied for failure to satisfy 
the reasonable expectation test or based on a finding that costs are 
not legitimate and verifiable. Puget argues that stranded cost 
recovery is constitutionally required and that the recovery 
mechanism must be amended to ensure full recovery of prudently 
incurred stranded costs, including PURPA contract costs.
---------------------------------------------------------------------------

    SC Public Service Authority also asks the Commission to allow the 
recovery of stranded costs that result from the loss of indirect 
customers (e.g., customers of wholesale requirements customers). It 
argues that if such indirect customers can get access to a new source 
of power through open access tariffs, the requirements of the utility's 
direct customer will decrease, and the supplying utility will suffer 
stranded costs. SC Public Service Authority states that because of the 
nexus between open access and the departure of the indirect customer, 
utilities that suffer stranded costs in the event of the loss of an 
indirect customer should have an opportunity to recover those costs 
under the reasonable expectation standard.
    A number of entities also ask the Commission to find that open 
access transmission and stranded cost recovery are necessary to 
accomplish the remedy ordered by the Commission and thus are not 
severable.<SUP>513 To this end, they submit that if the Commission's 
ability to provide for stranded cost recovery is reduced or 
substantially modified, public utilities should be able to withdraw 
filed tariffs or to file amended tariffs. It is their position that 
deletion or substantial change of the open access or stranded cost 
provisions by the Commission or by a court would vitiate the basis on 
which the Commission premised the Rule.
---------------------------------------------------------------------------

    \513\ E.g., EEI, Oklahoma G&E, Nuclear Energy Institute, 
Southern. Southern requests that the Commission add a section 35.29 
to the regulatory text providing: ``Sections 35.26 and 35.28 of this 
part constitute unseverable portions of a unitary action of the 
Commission.''
---------------------------------------------------------------------------

    In an effort to ensure that stranded cost recovery procedures do 
not become a vehicle for lengthy and expensive litigation over whether 
there is a sufficient nexus to open access, several entities ask the 
Commission to place on the departing generation customers the burden to 
demonstrate the absence of a nexus between their actions and the 
availability of open access transmission under the Rule in those cases 
where: (i) the contract has no term or termination provision; (ii) the 
Commission issues an order under section 206 reducing the term of the 
contract; or (iii) there is legitimate municipalization.<SUP>514
---------------------------------------------------------------------------

    \514\ E.g., Carolina P&L, PSE&G.
---------------------------------------------------------------------------

Commission Conclusion

    We will deny the requests for rehearing that ask us to expand the 
scope of stranded cost recovery to include situations in which the 
departing customer does not take unbundled transmission from its former 
supplier but instead obtains transmission from another utility or 
obtains power from a third party supplier who is located in the 
customer's service territory and thus requires no transmission from the 
former supplier.<SUP>515 As the Commission stated in Order No. 888, the 
premise of the Rule is that where the former requirements supplier had 
a reasonable expectation of serving beyond the contract term and the 
customer uses the open access transmission tariff of its former 
requirements supplier to obtain power from a new generation supplier, 
the customer must pay the costs that were incurred on its behalf under 
the prior regulatory regime. The Rule is not intended, however, to 
apply to the recovery of costs associated with the normal risks of 
competition, such as self-generation, cogeneration, or loss of load, 
that do not arise from the new, accelerated availability of non-
discriminatory open access transmission. If a customer leaves its 
utility supplier by exercising options that could have been undertaken 
prior to mandatory transmission under Order No. 888 or the Energy 
Policy Act, or that do not rely on access to the former seller's 
transmission (such as access to another power supplier through another 
utility's transmission system or self-generation), there is no direct 
nexus to Commission-mandated transmission access.
---------------------------------------------------------------------------

    \515\ We discuss in Section IV.J.6 below our disposition of the 
rehearing requests that support recovery of costs stranded as a 
result of municipal annexation or expansion. In response to EEI's 
argument that the Rule would deny recovery for costs stranded 
pursuant to a voluntarily-negotiated transmission service agreement 
and would discourage parties from settling transmission disputes, we 
find EEI's arguments in support of its position to be vague and 
cursory. However, we do not interpret the Rule in any way as 
precluding parties from addressing stranded cost issues through 
settlement, including settlement of a transmission dispute. To the 
contrary, we fully expect that the renegotiation of contracts, 
including transmission agreements, would provide parties with a 
useful means for resolving stranded cost issues without litigation. 
We believe that a negotiated rate that includes an amount for 
stranded cost recovery could be found to be just and reasonable.
---------------------------------------------------------------------------

    For example, if a customer is able to obtain power from a new 
supplier by using the transmission system of another utility, it is 
likely that the customer could have made these arrangements in the 
absence of the new open access rules. The new transmission provider 
would have had little incentive to deny transmission services to the 
customer in order to protect another utility's existing power supply 
arrangement, since it was not the customer's power supplier in the 
first place. As Order No. 888 suggested, it is likely that the 
neighboring utility would have a positive incentive to provide the 
transmission service in order to increase its transmission revenues, 
and that this incentive is unchanged by open access 
transmission.<SUP>516
---------------------------------------------------------------------------

    \516\ FERC Stats. & Regs. at 31,849-50; mimeo at 624-26.
---------------------------------------------------------------------------

    Although EEI and others argue that EPAct and the Commission's pre-
Order No. 888 efforts to expand transmission access have facilitated 
the exercise of pre-existing competitive options, the fact remains that 
such options historically were available before open access. For this 
reason, we conclude that costs incurred as a result of the exercise of 
pre-existing competitive options do not fall within the scope of Order 
No. 888.
    A number of entities argue that, even where the departing customer 
obtains access to another power supplier through the transmission 
system of another utility (i.e., not that of its former supplier), the 
power supply would not have been available to the customer if open 
access transmission rules were not in place to permit that power to 
move from distant generators over intervening utilities' transmission 
facilities. Some argue that there is no good policy reason for 
addressing stranded costs only where linked directly to the Open Access 
Rule (or to a section 211 order) because a variety of federal actions 
have created a competitive wholesale power market and the specter of 
stranded costs caused by customers departing their traditional utility. 
While these arguments may have superficial appeal, the effective result 
would be to provide for recovery of stranded costs from departing 
customers under the Rule no matter how tenuous the nexus to Commission-
mandated transmission access. The Commission has to exercise reasonable 
judgment and reasonable line drawing regarding the link between its 
actions in this Rule and the decision to allow an opportunity for 
extra-contractual stranded cost recovery from the departing customer. 
The Commission believes that requiring a direct nexus between 
Commission-mandated transmission access (namely, requiring that the 
departing customer obtain access to another power supplier through the 
use of its former supplier's Commission-required tariff--i.e., an open 
access tariff or a tariff ordered pursuant to section 211) and the 
special stranded cost recovery procedures of this Rule is the most 
reasoned and supportable approach because it establishes a clear link 
between availability of the transmission tariff

[[Page 12382]]

and the decision of the customer to seek an alternative supplier.
    With regard to potential stranded costs associated with situations 
that could have occurred prior to the Open Access Rule and prior to the 
Energy Policy Act (such as self-generation), under traditional 
ratemaking such costs (albeit not previously labeled as potential 
``stranded'' costs) would in most cases be reallocated in the next rate 
case to remaining customers. The fact that this Rule does not permit a 
utility to seek recovery of these types of costs from the departing 
customer does not mean that the Commission may not, in appropriate 
circumstances, permit their recovery through traditional ratemaking 
means. However, many factors will influence cost recovery in the 
future, including whether the utility is selling at cost-based or 
market-based rates and the transitional period to more competitive bulk 
power markets. The Commission will address these matters on a case-by-
case basis.
    We do not agree with those commenters who contend that the 
Commission's failure in Order No. 888 to allow for the recovery of 
costs incurred by a utility when a departing customer does not use the 
former supplier's transmission system to reach a new supplier would be 
confiscatory in violation of the Constitution. As the Supreme Court 
explained in Duquesne, ``[t]he guiding principle has been that the 
Constitution protects utilities from being limited to a charge for 
their property serving the public which is so `unjust' as to be 
confiscatory.''<SUP>517 However, Order No. 888 addresses only the 
recovery of legitimate, prudent and verifiable costs that are stranded 
if a former wholesale requirements customer or a former retail customer 
uses a Commission-mandated transmission tariff to reach a new supplier. 
As discussed above, Order No. 888 does not by its terms bar the 
recovery of costs that do not result from the use of Commission-
required transmission access (i.e., costs that result when a departing 
customer does not use the former supplying utility's open access 
tariff). Utilities may, as before, seek recovery of such non-open 
access-related costs on a case-by-case basis in individual rate 
proceedings. The Commission will not prejudge those issues here. As a 
result, the argument that the Commission's treatment of stranded costs 
in Order No. 888 (i.e., its failure to treat certain costs as costs for 
which recovery may be sought under the Rule) will result in rates that 
will be so unjust as to be confiscatory is misplaced.
---------------------------------------------------------------------------

    \517\ 488 U.S. at 307.
---------------------------------------------------------------------------

    We deny SC Public Service Authority's request that the Commission 
allow a utility to seek recovery of stranded costs that result from the 
loss of indirect customers (i.e., the loss of the utility's customer's 
customers). The Commission does not believe it is appropriate or 
feasible to allow a public utility (or a transmitting utility under 
section 211 of the FPA) to seek recovery of stranded costs from an 
indirect customer (i.e., a customer of a wholesale requirements 
customer of the utility). The reasonable expectation analysis would 
apply only to the direct wholesale customer of the utility, not to the 
indirect customer. A utility may seek to recover stranded costs from a 
direct wholesale customer (subject to the requirements of the Rule), 
but it is up to the direct wholesale customer, through its contracts 
with its customers or through the appropriate regulatory authority, to 
seek to recover stranded costs from its customers.
    We also deny PSE&G's and Carolina P&L's request that a utility be 
allowed to seek stranded cost recovery in cases where the departing 
customer uses the Commission's Mobile-Sierra finding to get out of the 
contract under the just and reasonable standard and uses alternative 
suppliers and alternative transmission.<SUP>518 We disagree with their 
argument that the only way that the customer could have availed itself 
of a Mobile-Sierra finding was as a result of the Commission's open 
access rules and thus the necessary nexus is met. A customer to a 
Mobile-Sierra contract always has the option of instituting a 
proceeding under section 206 of the FPA and making a showing of why, 
under Mobile-Sierra, it is in the public interest to modify the 
contract.
---------------------------------------------------------------------------

    \518\ These parties appear to refer to a situation in which a 
customer is able to modify or terminate its contract, but would use 
the transmission system of a utility other than that of its former 
supplier in order to reach a new generation supplier. In this 
circumstance, the Rule would not permit the former supplier to seek 
stranded costs.
---------------------------------------------------------------------------

    We will not, at this time, make any determination whether or not 
the requirements of open access transmission and stranded cost recovery 
are severable. As we indicated in Order No. 888, we issued the Stranded 
Cost Final Rule simultaneously with the Open Access Rule because we 
believe that the recovery of legitimate, prudent and verifiable 
stranded costs is critical to the successful transition of the electric 
industry to a competitive, open access environment.<SUP>519 We believe 
that our decision to allow stranded cost recovery will be upheld by the 
courts. Moreover, as we discuss in Section IV.A.1 above, it would be 
premature to consider at this time what the Commission would do if one 
or more of the provisions of the Rule are not upheld. Circumstances at 
the time of any court order would dictate how we should proceed and we 
would consider all such circumstances, and the entirety of our policy 
decisions, before determining how to respond to a court decision.
---------------------------------------------------------------------------

    \519\ FERC Stats. & Regs. at 31,789-90; mimeo at 454-55.
---------------------------------------------------------------------------

    Further, we decline to place on departing generation customers the 
burden of demonstrating that no nexus exists between their actions and 
the availability of open access transmission under the Rule in cases 
involving no term or termination provision, an order under section 206 
reducing the term of the contract, or municipalization. The proponents 
of such a proposal, Carolina P&L and PSE&G, attempt to justify it as a 
means to ensure that stranded cost recovery procedures do not become a 
vehicle for lengthy and expensive litigation over whether there is a 
sufficient nexus to open access in the three identified situations. 
However, Order No. 888 places the burden on the utility seeking 
stranded cost recovery to demonstrate that the costs for which it seeks 
recovery fall within the scope of the Rule and that it had a reasonable 
expectation of continuing service. In this regard, the Rule tracks the 
requirement of sections 205 and 206 of the FPA that a public utility 
demonstrate the justness and reasonableness of its proposed rates. 
Carolina P&L and PSE&G fail to explain why it would be appropriate for 
customers (as opposed to the utilities seeking recovery) in the three 
identified situations to bear the initial burden of demonstrating why 
costs should not be recovered from them under the Rule.<SUP>520 As a 
result, we reject their proposal.<SUP>521
---------------------------------------------------------------------------

    \520\ In addition, the proposal would not eliminate lengthy 
litigation. It would only change the burden of proof in whatever 
litigation occurs.
    \521\ We note, however, that in a section 206 proceeding brought 
by a customer seeking to shorten or terminate a contract, the 
customer has the burden (as it would in any section 206 case that it 
initiates) of presenting sufficient evidence that the contract is no 
longer just and reasonable. As we stated in the Rule, the utility 
must present any stranded cost claim at that time. See FERC Stats. & 
Regs. at 31,664, 31,813; mimeo at 86-87, 521-22.
---------------------------------------------------------------------------

Rehearing Requests--Stranded Cost Recovery By Transmitting Utilities 
That Are Not Public Utilities

    A number of entities contend that the Commission's decision to 
limit stranded cost recovery for transmitting utilities that are not 
public utilities to section

[[Page 12383]]

211 proceedings is inconsistent with its decision to impose the 
reciprocity requirement on those utilities, violative of the principle 
of comparability, and unduly discriminatory and 
anticompetitive.<SUP>522 NRECA submits that if the Commission has the 
statutory authority to require non-public utilities to render 
transmission service outside of a section 211 proceeding through the 
reciprocity, RTG and power pool provisions of the Rule, then it must 
exercise that authority to ensure stranded cost recovery by such non-
public utilities. Noting that the Rule does not address how a non-
public utility that chooses voluntarily to provide an open access 
tariff can recover its stranded costs, SC Public Service Authority asks 
the Commission to confirm on rehearing that non-jurisdictional 
utilities can include a provision for recovery of stranded costs in 
their tariffs provided pursuant to the Final Rule.
---------------------------------------------------------------------------

    \522\ E.g., NRECA, TDU Systems, Dairyland Coop.
---------------------------------------------------------------------------

Commission Conclusion

    The Commission's jurisdiction over the recovery of stranded costs 
by non-public utilities, and thus our ability to permit an opportunity 
for recovery of such costs, is limited by statute. While we have the 
statutory authority to ensure that non-public utilities have the 
opportunity to seek recovery of stranded costs in proceedings under 
sections 211 and 212 of the FPA,<SUP>523 we do not have such authority 
under sections 205 and 206 of the FPA. However, we clarify that nothing 
in the Final Rule was intended to preclude non-public utilities from 
including stranded cost provisions in voluntary reciprocity tariffs or 
from otherwise recovering stranded costs under applicable law. We 
discuss these matters in detail below.
---------------------------------------------------------------------------

    \523\ Stranded costs could also conceivably arise as a result of 
an ordered interconnection under section 210. However, the rates for 
such an interconnection would be established pursuant to section 212 
and could therefore also include stranded costs.
---------------------------------------------------------------------------

    As we stated in Order No. 888 in response to commenters' objections 
that the Rule would give public utilities a greater opportunity than 
other transmitting utilities to recover stranded costs, our 
jurisdiction over transmitting utilities that are not also public 
utilities is limited. If the selling utility is a transmitting utility 
that is not a public utility, its power sales contracts are not subject 
to this Commission's jurisdiction under sections 205 and 206 of the 
FPA. Thus, we can provide such a transmitting utility an opportunity to 
recover stranded costs only through Commission-jurisdictional 
transmission rates fixed under sections 211 and 212 of the FPA.<SUP>524
---------------------------------------------------------------------------

    \524\ FERC Stats. & Regs. at 31,791; mimeo at 458. If such a 
transmitting utility seeks stranded cost recovery in a proceeding 
under sections 211 and 212, it would, consistent with the provisions 
of the Rule, be limited to recovery associated with requirements 
contracts executed on or before July 11, 1994 that do not contain an 
exit fee or other explicit stranded cost provision.
---------------------------------------------------------------------------

    The open access tariff reciprocity provision, which applies to all 
open access customers that own, operate, or control transmission 
facilities or are affiliates of entities that own, operate or control 
such facilities, and that do not obtain a waiver of the provision, does 
not create jurisdiction for the Commission to fix the rates for these 
utilities. Contrary to the suggestions of some, the tariff reciprocity 
provision is not based on any statutory authority of the Commission to 
require non-public utilities to render transmission service outside of 
a section 211 proceeding. As we make clear in Order No. 888, we do not 
have authority under sections 205 and 206 of the FPA to require non-
public utilities to file tariffs (or rate schedules for that matter) 
with the Commission.<SUP>525 In permitting a public utility to deny 
transmission service to any person that requests service under an open 
access tariff unless that person provides reciprocal non-discriminatory 
transmission services to the transmission provider, we are not acting 
under any statutory authority to require non-public utilities to 
provide transmission access. Rather, out of fairness, we are 
conditioning the use of open access services by all customers, 
including non-public utilities, on an agreement to offer comparable 
transmission services in return to the public utility transmission 
provider.<SUP>526
---------------------------------------------------------------------------

    \525\ FERC Stats. & Regs. at 31,691; mimeo at 162.
    \526\ FERC Stats. & Regs. at 31,760-62; mimeo at 370-74.
---------------------------------------------------------------------------

    We clarify that a non-public utility that chooses voluntarily to 
offer an open access tariff for purposes of demonstrating that it meets 
the reciprocity provision can include a stranded cost provision in its 
tariff. However, adjudication of any stranded cost claims under that 
tariff is not subject to the Commission's jurisdiction.<SUP>527 With 
the exception of our section 210 interconnection and sections 211-212 
transmission rate jurisdiction, we do not have jurisdiction over the 
rates of non-public utilities. If a non-public utility wishes to 
recover stranded costs pursuant to a tariff or otherwise, it can seek 
to do so subject to the review of the appropriate regulatory 
authority.<SUP>528
---------------------------------------------------------------------------

    \527\ Although the Commission would not determine the rate, 
including the stranded cost component of the rate, of a non-public 
utility, we would review a public utility's claim that it is 
entitled to deny service to a non-public utility because the 
stranded cost component of the non-public utility's transmission 
rate is being applied in a way that violates the principle of 
comparability.
    \528\ We note that in the case of stranded cost claims presented 
to the Commission by BPA or one of the other PMAs, our review would 
be limited to that set forth in the applicable statutes and any 
relevant delegation of authority from the Secretary of Energy. See, 
e.g., Pacific Northwest Electric Power Planning and Conservation 
Act, 16 U.S.C. Sec. 839-839h (1985) (Northwest Power Act); 
Department of Energy Delegation Order No. 0204-108, as amended, 48 
FR 55,664 (1983), amended, 51 FR 19,744 (1986), amended, 56 FR 
41,835 (1991), amended, 58 FR 59,716 (1993) (delegation order 
relating to Western Area Power Administration).
---------------------------------------------------------------------------

Rehearing Requests--Stranded Cost Recovery for Transmission Dependent 
Utilities

    NRECA and TDU Systems challenge the Commission's decision not to 
guarantee a transmission dependent utility that is not a public utility 
stranded cost recovery when the transmission dependent utility's 
customers leave its system by using the open access tariff of another 
utility. They submit that the ability of transmission dependent 
utilities to compete with public utility transmission providers in an 
open access environment would be severely affected by their inability 
to recover stranded costs on a basis comparable to those transmission 
providers. They argue that the open access provisions of Order No. 888 
will result in the stranding of costs incurred by non-transmission 
owning, non-public utilities to serve customers that depart to other 
suppliers. They contend that these customers are already located in 
close proximity to, and interconnected to, public utilities; thus it is 
likely that they would use the open access tariffs of these public 
utilities to obtain their new power supplies. NRECA and TDU Systems 
argue that this situation should meet the ``but for open access'' 
nexus. On this basis, they assert that Order No. 888 is no less the 
proximate cause of the departure of customers of transmission dependent 
utilities than it is of the departure of public utility transmission 
owners' customers. They object that the Commission takes no account of 
the anticompetitive effects of disregarding costs stranded on 
transmission dependent utilities' systems as a result of open access.
    Dairyland Coop asks the Commission to recognize a generation and 
transmission (G&T) cooperative and its member distribution cooperatives 
as a single economic unit for purposes of stranded cost recovery (such 
that conversion of a distribution

[[Page 12384]]

cooperative's retail customer to a wholesale customer may result in 
stranded costs for the G&T cooperative). It objects that the Commission 
implicitly rejected comments to this effect without discussion in Order 
No. 888.

Commission Conclusion

    We deny the requests for rehearing of our decision not to permit 
transmission dependent utilities and electric cooperatives to seek 
stranded cost recovery unless they are public utilities or transmitting 
utilities that would otherwise qualify under the Rule. With regard to 
transmission dependent utilities, as we indicated in Order No. 888, the 
limited opportunity for stranded cost recovery contained in the Rule 
would not likely apply in the case of transmission dependent utilities, 
who own little or no transmission and the majority of whom would not be 
public utilities or transmitting utilities subject to the Commission's 
jurisdiction.<SUP>529 The opportunity for extra-contractual wholesale 
stranded cost recovery is allowed only where the departing customers 
use open access (or section 211 access) on the transmission systems of 
their former generation suppliers and only for a discrete set of 
requirements contracts executed on or before July 11, 1994 that do not 
contain explicit stranded cost provisions (involving the bundled 
provision of generation and transmission) and retail-turned-wholesale 
situations for which the utility can demonstrate that it had a 
reasonable expectation of continuing service. Even though it may be the 
case that transmission dependent utilities lose generation customers 
that are able to use open access tariffs of other utilities to reach 
new suppliers, there was nothing to keep these other utilities from 
offering such transmission service before Order No. 888. These other 
utilities had no economic incentive to deny such service before Order 
No. 888. Thus, in the scenario posited in the rehearings, the 
transmission dependent utilities do not meet the fundamental premise of 
the Rule: that a utility that historically has supplied bundled 
generation and transmission services to a wholesale requirements 
customer and incurred costs to meet reasonably expected customer demand 
should have an opportunity to recover legitimate, prudent and 
verifiable costs that may be stranded because open access use of the 
utility's transmission system enables a generation customer to shop for 
power.<SUP>530
---------------------------------------------------------------------------

    \529\ FERC Stats. & Regs. at 31,790; mimeo at 456-57.
    \530\ FERC Stats. & Regs. at 31,790; mimeo at 456-57.
---------------------------------------------------------------------------

    However, this is not to say that a transmission dependent utility 
that is not a public utility, or other non-public utility entities 
(such as RUS-financed cooperatives), cannot seek recovery of the cost 
of any resulting uneconomic assets through their contracts with their 
customers or through the appropriate regulatory authority. The 
Commission has no objection to these entities being able to seek such 
cost recovery through the appropriate regulatory channels. However, 
because the Commission does not have jurisdiction over these entities 
(other than through sections 211 and 212 in the case of non-public 
utility transmitting utilities), it does not have authority to allow 
them to recover these costs.<SUP>531
---------------------------------------------------------------------------

    \531\ Unless these entities own some transmission used in 
interstate commerce or are engaged in sales for resale, and are not 
otherwise exempt under FPA section 201(f), they would not be public 
utilities under sections 205 and 206. Most transmission dependent 
utilities are not public utilities.
---------------------------------------------------------------------------

    We also deny Dairyland Coop's request that the Commission recognize 
a G&T cooperative and its member distribution cooperatives as a single 
economic unit for purposes of stranded cost recovery. If a cooperative 
obtains its financing through RUS, it is not a public utility subject 
to our jurisdiction under sections 205 and 206 of the FPA. Although the 
Commission has no objection to these G&T cooperatives being able to 
seek cost recovery (including recovery of costs on behalf of their 
distribution cooperatives) through the appropriate regulatory channels, 
this Commission does not have authority to allow them to seek recovery 
of stranded costs unless access is obtained through a section 211 
order.<SUP>532
---------------------------------------------------------------------------

    \532\ A G&T cooperative that is a transmitting utility could 
seek recovery of stranded costs if it is ordered to provide 
transmission services that permit its distribution cooperative to 
reach another supplier and if it had a requirements contract with 
the distribution cooperative that was executed on or before July 11, 
1994.
---------------------------------------------------------------------------

    In the case of a G&T cooperative that is a public utility (of which 
there are just a handful at the present time), such a cooperative would 
have to have a jurisdictional wholesale requirements contract with its 
distribution cooperative in order to be able to seek recovery of 
stranded costs under the Rule. In the case of a jurisdictional G&T 
cooperative, the request that the G&T be treated as a single economic 
unit with the distribution cooperative (such that departure of a 
distribution cooperative's retail customer would be treated as 
resulting in stranded costs for the G&T cooperative for which the G&T 
could seek recovery) is, in effect, a request for recovery of stranded 
costs from an indirect customer. As we discuss above, the Commission 
does not believe it is appropriate or feasible to allow a public 
utility (or a transmitting utility under section 211 of the FPA) to 
seek recovery of stranded costs from an indirect customer (i.e., a 
customer of a wholesale requirements customer of the utility) under 
this Rule. The reasonable expectation analysis would apply only to the 
direct wholesale customer of the utility, not to the indirect customer. 
It is up to the direct wholesale customer of the utility, through its 
contracts with its customers or through the appropriate regulatory 
authority, to seek to recover such costs from its customers.
    Commenters have provided no basis for making an exception in the 
case of cooperatives. Moreover, to treat a G&T cooperative and its 
member distribution cooperatives as a single economic unit for stranded 
cost purposes would be inconsistent with the Commission's decision not 
to treat cooperatives as a single unit for purposes of Order No. 888's 
reciprocity provision.
    In Order No. 888, in response to arguments raised by cooperatives, 
the Commission agreed to limit the reciprocity requirement to corporate 
affiliates. In other words, if a G&T cooperative seeks open access 
transmission service from the transmission provider, only the G&T 
cooperative (not its member distribution cooperatives) would be 
required to offer transmission service. If a member distribution 
cooperative itself receives transmission service from the transmission 
provider, then it (but not its G&T cooperative) must offer reciprocal 
transmission service over its interstate transmission facilities, if 
any.<SUP>533 Dairyland has provided no basis to support treating 
cooperatives differently for stranded cost purposes and reciprocity 
purposes. We accordingly will deny Dairyland's request for rehearing on 
this issue.
---------------------------------------------------------------------------

    \533\ FERC Stats. & Regs. at 31,763; mimeo at 377-78.
---------------------------------------------------------------------------

Rehearing Requests Opposing Limitation of Recovery to Wholesale 
Requirements Customers

    PA Munis argues that it is inequitable and anticompetitive for 
``wholesale requirements customers'' but not other ``wholesale 
customers'' to have to pay stranded costs, repeating an argument that 
it made in its comments on the supplemental stranded cost NOPR. It says 
that there is no difference in the firm power provided by public 
utilities

[[Page 12385]]

to ``wholesale requirements customers'' and to ``wholesale customers'' 
and no difference in the generating facilities required and the costs 
of operation between the production of firm capacity and energy 
required for ``wholesale requirements sales'' and ``wholesale sales.'' 
PA Munis submits that the total amount of wholesale requirements power 
purchased in the United States is less than two percent of the total 
amount of firm power sales. It argues that requiring only wholesale 
requirements customers to pay stranded costs would restrict the ability 
of such customers to switch suppliers while not similarly restricting 
large firm wholesale customers. It contends that wholesale firm 
requirements customers therefore will not have equal access under the 
Rule because of the increased transmission rates for stranded costs 
that would not be levied on other large wholesale firm customers. Pa 
Munis says this produces the same result found unlawful in the Maryland 
People's Counsel case <SUP>534--equal access to all wholesale customers 
is virtually denied by the chilling effect of stranded costs borne only 
by wholesale requirements customers.
---------------------------------------------------------------------------

    \534\ Maryland People's Counsel v. FERC, 761 F.2d 780 (D.C. Cir. 
1985) (Maryland People's Counsel I). See also Maryland People's 
Counsel v. FERC, 761 F.2d 768 (D.C. Cir. 1985) (Maryland People's 
Counsel II).
---------------------------------------------------------------------------

Commission Conclusion

    In Order No. 888, the Commission fully addressed the concerns of PA 
Munis. We again address below the major distinctions between 
requirements and other customers and deny rehearing.
    In Order No. 888, we explained that the historical and practical 
relationship between a utility and its wholesale requirements 
customers, including the expectation of continued service, justifies 
allowing public utilities the opportunity to seek to recover the 
stranded costs covered by this Rule from only those customers and not 
from non-requirements customers that contract separately for 
transmission services to deliver their purchased power or from 
wholesale customers that purchase non-requirements power. Requirements 
customers historically were long-term customers who by definition 
depended upon their local suppliers because they were captive 
customers. Utilities had no obligation to provide transmission service 
that would allow these customers to reach other suppliers, and there 
were no other transmission facilities in proximity to those of the 
supplying utility. And the service involved requirements power; that 
is, these customers were dependent upon the wholesale supplier for all 
or part of their power. Utilities thus assumed they would continue 
serving these customers and may have made significant investments based 
on that long-term expectation. These same assumptions cannot be made 
for short-term, non-firm transactions and other wholesale non-
requirements firm transactions. Unlike requirements customers, these 
customers had other options. Thus, the supplying utility could not 
assume that these customers would remain on its system.
    With regard to short-term transactions, utilities did not (and do 
not today) generally make investments for short-term economy-type 
transactions. Rather, such transactions were entered into only when the 
utility temporarily had available capacity or energy that could be 
provided to the buyer at a price higher than the seller's incremental 
cost and lower than the buyer's decremental cost. The utility was not 
obligated in any way--either explicitly or implicitly--to provide for 
the needs of coordination customers. Because coordination transactions 
were not the cause of stranded investment decisions, it would be 
inappropriate to allocate such costs to non-requirements 
customers.<SUP>535
---------------------------------------------------------------------------

    \535\ FERC Stats. & Regs. at 31,790-91; mimeo at 457-58.
---------------------------------------------------------------------------

    With regard to long-term, non-requirements firm transactions, such 
as unit power sales contracts, we note that there was no implied 
obligation to serve customers to these transactions as there was for 
requirements customers. Generating units were not built for the purpose 
of entering into these arrangements. Therefore, because utilities did 
not incur costs on behalf of non-requirements firm power sales 
customers, such customers have not caused costs to be stranded and 
should not be required to pay stranded cost charges. Accordingly, we 
reaffirm limiting the opportunity for stranded cost recovery to costs 
associated with wholesale requirements contracts.<SUP>536
---------------------------------------------------------------------------

    \536\ We clarify, however, that a contract may meet our 
definition of wholesale requirements contract even though it does 
not carry the label ``requirements contract.'' The definition refers 
to a contract that provides any portion of a customer's bundled 
wholesale power requirements. As discussed above, whether or not a 
contract meets this definition hinges upon whether the customer 
depended upon the wholesale supplier for all or part of its power 
because it could not obtain transmission access to reach other 
suppliers, i.e., it was captive to the historical local supplier.
---------------------------------------------------------------------------

    We recognize PA Munis' concern that if a utility meets the 
evidentiary requirements of the Rule and is allowed to recover stranded 
costs from wholesale requirements customers, such customers may see 
little or no savings in the short-term by switching power suppliers, 
since a stranded cost charge (in the form of either an exit fee or a 
surcharge on transmission) would be paid in addition to the power price 
paid a new supplier. However, as we discuss above and in Section IV.J.2 
below, we believe that stranded costs are transition costs that must be 
addressed at an early stage if we are to fulfill our regulatory 
responsibilities in moving to competitive markets. Further, as we 
explain in Section IV.J.3 below, although spreading the costs to all 
transmission users of a utility's system (rather than imposing them 
directly on the departing wholesale requirements customer) might enable 
the customer to see earlier power cost savings than would result if 
stranded costs were directly assigned to the customer, we have 
concluded that this potential benefit to a broad-based approach is 
outweighed by a significant countervailing disadvantage--namely, the 
violation of the cost-causation principle of ratemaking. The Commission 
rejects a broad-based approach for the electric industry primarily 
because the potential power cost savings to the departing generation 
customer would be realized only by shifting costs that are directly 
attributable to the departing generation customer to the other users of 
the utility's transmission system.
    Contrary to PA Munis's claim, we believe that the circumstances 
surrounding the opportunity to seek stranded cost recovery from 
wholesale requirements customers that is permitted in Order No. 888 are 
distinguishable from the issues that were before the court in the 
Maryland People's Counsel cases. Those cases involved challenges to 
Commission orders that permitted pipelines to transport gas at lowered 
prices to ``non-captive consumers'' (large industrial end users capable 
of switching to alternative fuels) without any obligation to provide 
the same service to ``captive consumers'' such as local distribution 
companies and their residential customers. In Maryland People's Counsel 
I, the court invalidated the Commission's authorization of a ``special 
marketing program'' under which a pipeline and its producer would agree 
to amend their high-priced gas purchase contract to permit the producer 
to sell the committed gas elsewhere at market prices and to credit the 
volume of such sales against the pipeline's high-priced purchase 
obligations. Eligibility to purchase the

[[Page 12386]]

cheaper released gas was limited to industrial users. The court found 
that the Commission had failed to provide a reasonable basis for its 
decision to exclude ``captive customers'' from eligibility to purchase 
the cheaper released gas.<SUP>537 In Maryland People's Counsel II, the 
court invalidated the Commission's approval of blanket authority for 
interstate transportation of natural gas sold directly by producers to 
fuel-switchable end users. The court held that the Commission had 
failed to consider the anticompetitive effects of failing to require 
the pipelines to provide the same service to captive consumers on 
nondiscriminatory terms.<SUP>538
---------------------------------------------------------------------------

    \537\ See 761 F.2d 768.
    \538\ See 761 F.2d at 781-82.
---------------------------------------------------------------------------

    In contrast to the Maryland People's Counsel cases, the Commission 
in Order No. 888 is not discounting services for one class of customers 
to the exclusion of another, nor is it ordering that public utilities 
provide transmission access to only a specified customer group. To the 
contrary, Order No. 888 requires all public utilities that own, control 
or operate facilities used for transmitting electric energy in 
interstate commerce to provide open access transmission to any 
``eligible customer,'' with ``eligible customer'' defined broadly to 
include ``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.'' <SUP>539 Among other 
things, Order No. 888 gives wholesale requirements customers that 
previously were captive customers of their public utility suppliers the 
opportunity at the expiration of their contracts to take unbundled 
transmission service from their former suppliers in order to reach new 
suppliers. At the same time, the Commission recognizes that the 
departure of a wholesale requirements customer in this circumstance may 
strand costs that the former supplying utility incurred based on a 
reasonable expectation that it would continue to serve the customer 
beyond the contract term. As a result, Order No. 888 gives the former 
supplying utility the opportunity to seek recovery of costs stranded by 
the wholesale requirements customer's departure.
---------------------------------------------------------------------------

    \539\ Pro Forma Open Access Transmission Tariff, section 1.11.
---------------------------------------------------------------------------

    In further contrast to the Maryland People's Counsel cases, the 
Commission addresses in this Order (above) PA Munis' claim that it is 
inequitable and anticompetitive that only wholesale requirements 
customers and not other wholesale customers are subject to the stranded 
cost provisions of Order No. 888. The Commission has explained in 
detail the rationale for its decision that public utilities should be 
allowed an opportunity to seek to recover the stranded costs covered by 
this Rule only from wholesale requirements customers. The Commission 
has also addressed in Section IV.J.2 below the concerns expressed by 
some as to the potential anticompetitive effect of stranded cost 
charges.

Rehearing Request--ERCOT

    The TX Com <SUP>540 asks the Commission to clarify that ERCOT 
utilities may not use a section 211 proceeding as a vehicle to obtain 
wholesale or retail stranded cost recovery. <SUP>541 It notes that 
based on the definitions in section 35.26 of ``wholesale stranded 
cost'' <SUP>542 and ``wholesale transmission service,'' <SUP>543 the 
Rule applies only to interstate service and does not apply to the 
intrastate service provided by the utilities within ERCOT, yet the 
Commission suggests that it might permit a utility in ERCOT to recover 
stranded costs in a section 211 proceeding. Even if the Commission 
concludes that it has the authority to resolve stranded cost issues for 
ERCOT utilities, TX Com asks the Commission to establish a preference 
for resolution of transmission and stranded cost issues in ERCOT by TX 
Com. It suggests that uncertainty and gaming as to the choice of a 
forum could be avoided by executing a Memorandum of Understanding 
between TX Com and the Commission that would require interested persons 
to submit disputes to TX Com. Further, to the extent that the new ERCOT 
transmission access rules adopted by the TX Com may be deemed as the 
cause of stranded costs in ERCOT, TX Com asserts that it should be 
allowed to resolve issues related to such stranded costs.
---------------------------------------------------------------------------

    \540\ TX Com's request for rehearing was filed out-of-time on 
May 29, 1996 with a request that the Commission accept the rehearing 
request for filing as of May 24, 1996. TX Com explains it had made 
arrangements with a courier company to pick up its rehearing request 
on May 23, 1996 and deliver and file the rehearing request with the 
Commission before 5 p.m. on May 24, 1996. TX Com states that the 
courier company failed to pick up the rehearing request on May 23 as 
previously arranged. TX Com says that when it became aware on May 24 
that its rehearing request was not enroute to the Commission, it 
faxed a copy of the rehearing request to a copier and delivery 
service in Washington, D.C. The pleading, which was not signed, was 
delivered to the Commission prior to 5 p.m. on May 24. TX Com states 
that Commission personnel rejected the filing apparently because it 
was not signed. TX Com asks that the Commission find good cause 
under Rule 2001 of the Commission's Rules of Practice and 
Procedures, 18 CFR 385.2001 (1996), to accept its rehearing request 
for filing as of May 24, 1996. Under the circumstances, we will 
accept the rehearing request for filing as of May 24, 1996.
    \541\ Texas Utilities Electric Company filed on June 21, 1996 a 
motion for leave to file and response to TX Com's rehearing request. 
Texas Utilities opposes TX Com's positions on rehearing. While 
answers to requests for rehearing generally are not permitted, 18 
CFR 385.213(a)(2) (1996), we will depart from our general rule 
because of the significant nature of this proceeding and will accept 
Texas Utilities' response.
    \542\ ``Wholesale stranded cost'' is defined as ``any 
legitimate, prudent and verifiable cost incurred by a public utility 
or a transmitting utility to provide service to: (1) a wholesale 
requirements customer that subsequently becomes, in whole or in 
part, an unbundled wholesale transmission services customer of such 
public utility or transmitting utility; or (ii) a retail customer, 
or a newly created wholesale power sales customer, that subsequently 
becomes, in whole or in part, an unbundled wholesale transmission 
services customer of such public utility or transmitting utility.'' 
Order No. 888, mimeo at 768.
    \543\ ``Wholesale transmission services'' is defined as 
``ha[ving] the same meaning as provided in section 3(24) of the 
Federal Power Act (FPA): the transmission of electric energy sold, 
or to be sold, at wholesale in interstate commerce.'' Order No. 888, 
mimeo at 768.
---------------------------------------------------------------------------

Commission Conclusion

    In City of College Station, Texas,<SUP>544 the Commission repeated 
its view, first articulated in 1979, that sections 211 and 212 of the 
FPA clearly give the Commission jurisdiction to order transmission 
services within ERCOT, subject to the special rate provision for ERCOT 
utilities in section 212(k).<SUP>545 The Commission indicated that if 
it issues a final order in that case setting rates for transmission 
services within ERCOT, it will comply with section 212(k) and give 
deference to the TX Com's ratemaking methodology insofar as practicable 
and consistent with section 212(a).
---------------------------------------------------------------------------

    \544\ 76 FERC para. 61,138 (1996).
    \545\ Section 212(k), added by EPAct, provides as follows: (1) 
RATES.--Any order under section 211 requiring provision of 
transmission services in whole or in part within ERCOT shall provide 
that any ERCOT utility which is not a public utility and the 
transmission facilities of which are actually used for such 
transmission service is entitled to receive compensation based, 
insofar as practicable and consistent with subsection (a), on the 
transmission ratemaking methodology of the Public Utility Commission 
of Texas. 16 U.S.C. Sec. 824k(k) (1994).
---------------------------------------------------------------------------

    Our jurisdiction to order transmission services within ERCOT 
includes the authority to address costs that are stranded by a section 
211 transmission order.<SUP>546 Consistent with the special rate 
provision in section 212(k), we clarify

[[Page 12387]]

that we will give deference to the TX Com's ratemaking methodology, 
including any provisions or procedures related to stranded cost 
recovery, insofar as it is practicable and consistent with section 
212(a) and consistent with the principle of comparability set out in 
Order No. 888.
---------------------------------------------------------------------------

    \546\ To clarify that the Order No. 888 stranded cost provisions 
apply to the intrastate utilities within ERCOT, solely in the 
context of a section 211 proceeding, we will revise the definition 
of ``wholesale transmission services'' in section 35.26(b)(3) to 
read: ``Wholesale transmission services means the transmission of 
electric energy sold, or to be sold, at wholesale in interstate 
commerce or ordered pursuant to section 211 of the Federal Power Act 
(FPA).''
---------------------------------------------------------------------------

2. Cajun Electric Power Cooperative, Inc. v. FERC <SUP>547
---------------------------------------------------------------------------

    \547\ 28 F.3d 173 (D.C. Cir. 1994) (Cajun).
---------------------------------------------------------------------------

    In Order No. 888, the Commission explained why it does not 
interpret the Cajun court decision as barring the recovery of stranded 
costs and why the record developed in this generic proceeding fully 
addresses the court's concerns regarding meaningful access to 
alternative suppliers.<SUP>548
---------------------------------------------------------------------------

    \548\ FERC Stats. & Regs. at 31,793-95; mimeo at 464-70.
---------------------------------------------------------------------------

    We also addressed the court's concern that the method of recovery 
in that case (a charge in the departing customer's transmission rate) 
might constitute an anticompetitive tying arrangement. We explained 
that the stranded cost recovery procedure we prescribe in the Open 
Access Rule is only a transitional mechanism that is intended to enable 
utilities to recover costs prudently incurred under a different 
regulatory regime. The purpose and effect of the stranded cost recovery 
mechanism that we approved in the Rule is to facilitate the transition 
to competitive wholesale power markets. We concluded that while 
stranded cost recovery may temporarily delay some of the benefits of 
competitive bulk power markets for some customers, such transition 
costs must be addressed at an early stage if we are to fulfill our 
regulatory responsibilities in moving to competitive markets.
    In reaching these conclusions, the Commission applied the 
traditional regulatory concept of cost causation. We stated that it is 
not an illegal tying arrangement to hold a customer accountable for the 
cost consequence of leaving an incumbent supplier if, under our rules, 
the incumbent supplier must show a reasonable expectation of providing 
continuing service to that customer before it can recover stranded 
costs from the customer.
    In addition, in response to the Cajun court and commenters in this 
proceeding as to the need to provide as much certainty as possible for 
departing customers concerning their potential stranded cost 
obligation, the Commission included a formula for calculating a 
departing customer's potential stranded cost obligation. We explained 
that the revenues lost formula is designed to provide certainty for 
departing customers and to create incentives for the parties to address 
stranded cost claims between themselves without resort to litigation.

Rehearing Requests Arguing That the Commission Has Not Resolved the 
Cajun Court's Concerns

    Several entities submit that the Commission has not resolved the 
Cajun court's tying concerns. They argue that tying arrangements are 
still the essence of the stranded cost recovery method mandated by 
Order No. 888, and that a tying arrangement is a per se antitrust 
violation that is not subject to justification by reference to the 
reasons for the restraint or the expected ancillary benefits.<SUP>549 A 
number of these entities object that the Commission does not address 
the court's substantive concern that a stranded cost provision is the 
antithesis of competition.<SUP>550 Several object that the Commission 
brushes aside the acknowledged anticompetitive effects of the rule as 
being ``transitional only,'' suggesting that short-term anticompetitive 
impacts are acceptable as long as the Commission is doing something 
that will be good for customers in the long term.<SUP>551 They also 
contend that the anticompetitive effects would not be limited to a 
transitional period, or that the transitional period could last 
indefinitely, thereby diluting or even nullifying the benefits of 
competition for years to come.<SUP>552
---------------------------------------------------------------------------

    \549\ See, e.g., ELCON, Suffolk County, Central Illinois Light, 
American Forest & Paper, TDU Systems, Blue Ridge, Nucor, IN Consumer 
Counselor, IN Consumers, APPA, PA Munis, VT DPS, Valero.
    \550\ E.g., Central Illinois Light, American Forest & Paper.
    \551\ E.g., American Forest & Paper, PA Munis.
    \552\ E.g., American Forest & Paper, Occidental Chemical, PA 
Munis.
---------------------------------------------------------------------------

    Several entities submit that the Commission erred in concluding 
that the stranded cost rules contained in Order No. 888 would allow 
customers ``meaningful'' access to alternative power suppliers.<SUP>553 
Among other things, these entities contend that there is no showing in 
the Order that transmission providers will not continue to exercise 
monopoly power over their transmission systems and that competition in 
generation will not be stifled by the stranded cost recovery mechanism.
---------------------------------------------------------------------------

    \553\ E.g., Arkansas Cities, IN Consumer Counselor, IN 
Consumers, Occidental Chemical, PA Munis.
---------------------------------------------------------------------------

    Some entities also object that the stranded cost procedures 
contained in Order No. 888 fail to provide certainty in the computation 
of recoverable stranded costs. They argue that the prospect of stranded 
cost liability and related litigation add costs of potential deal-
killing magnitude to any power supply acquisition considered by a 
customer.<SUP>554
---------------------------------------------------------------------------

    \554\ E.g., APPA, Arkansas Cities.
---------------------------------------------------------------------------

    APPA and ELCON challenge the Commission's description of Western 
Resources, Inc. v. FERC <SUP>555 as affirming the Commission's ability 
to allow stranded cost recovery. APPA argues that Western Resources 
does not justify the stranded cost provisions of Order No. 888 because 
it was a filed rate doctrine case, not a stranded cost case. APPA says 
that Western Resources involved no consideration of any allegation of 
anticompetitive conduct and no allegation that the utilities' proposal 
constituted an illegal tying arrangement.
---------------------------------------------------------------------------

    \555\ 72 F.3d 147 (D.C. Cir. 1995) (Western Resources).
---------------------------------------------------------------------------

Commission Conclusion

    We will deny the requests for rehearing advanced on the basis of 
the Cajun case. We disagree with those entities that contend that the 
Commission has not resolved the Cajun court's tying concerns. As an 
initial matter, we note that the parties that have raised this issue on 
rehearing ignore the fact that while this Commission has a 
responsibility to consider the anticompetitive effects of regulated 
aspects of interstate utility operations,<SUP>556 it has other 
statutory and regulatory public interest considerations which it must 
balance in order to engage in reasoned decisionmaking. In this 
proceeding, we have carefully balanced our responsibilities to remedy 
undue discrimination and to consider anticompetitive effects, our goal 
to eliminate market power of utilities and anticompetitive effects in 
the long run, and the need to provide a transition to competitive 
markets that is fair, that maintains a stable electric utility 
industry, and that recognizes the obligations incurred in a past, non-
competitive regulatory regime. As discussed below, we do not believe 
that the stranded cost proposal adopted in the Rule results in an 
illegal tying arrangement, as argued on rehearing. We believe we have 
given reasoned consideration to any potential transitory

[[Page 12388]]

anticompetitive effects of our stranded cost policy and that we have 
met the directives of the court in Cajun.
---------------------------------------------------------------------------

    \556\ The Commission's power under the FPA carries with it the 
responsibility to consider, in appropriate circumstances, the 
anticompetitive effects of regulated aspects of interstate 
operations pursuant to sections 202 and 203, and under like 
directives contained in sections 205, 206, and 207. Gulf States 
Utilities Company v. FPC, 411 U.S. 747 (1973). While the Commission 
lacks principal responsibility for implementing antitrust policy, it 
retains an obligation to give reasoned consideration to the bearing 
of antitrust policy on matters within its jurisdiction. Alabama 
Power Company, et al. v. FPC, 511 F.2d 383 (D.C. Cir. 1974).
---------------------------------------------------------------------------

    In considering the Cajun decision, it is important to note that the 
Cajun court assumes the presence of a competitive market in the 
electric utility industry, but such a competitive market does not now 
exist. Instead, the Commission is in the process of trying to bring 
about a competitive market and to manage the transition 
thereto.<SUP>557 When the Commission undertook a similar restructuring 
in the gas industry, the D.C. Circuit invalidated the Commission's 
efforts precisely because the Commission had failed to deal with the 
stranded cost problem in a satisfactory manner.<SUP>558
---------------------------------------------------------------------------

    \557\ In contrast to the situation in Order No. 888, the Cajun 
court did not have before it a generic, Commission-imposed recovery 
mechanism for distinguishing stranded costs associated with the 
Commission's ordering of industry-wide open access from all 
uneconomic costs.
    \558\ See AGD, 824 F.2d at 1021.
---------------------------------------------------------------------------

    As we indicated in Order No. 888, we do not believe it is an 
illegal tying arrangement to hold a customer accountable for the 
consequences of leaving an incumbent supplier if, before the incumbent 
supplier can recover legitimate, prudent and verifiable stranded costs 
from the departing customer, it must show that it incurred costs to 
provide service to the customer based on a reasonable expectation of 
continuing to serve the customer. Order No. 888 provides no guarantee 
of stranded cost recovery. Moreover, Order No. 888 provides the 
opportunity to recover stranded costs only for a discrete set of 
wholesale requirements contracts--those executed on or before July 11, 
1994 that do not contain an exit fee or other explicit stranded cost 
provision--and for retail-turned-wholesale customers. Thus, it is not 
necessarily the case that customers will have to pay stranded costs 
when they leave their current suppliers. To the contrary, before a 
utility can recover stranded costs from a customer, the utility must 
overcome certain evidentiary hurdles (including a rebuttable 
presumption of no reasonable expectation of continuing service if the 
contract contains a notice of termination provision). Particularly 
given the narrowly tailored circumstances under which stranded cost 
recovery is permissible under the Rule, we do not view it as the 
antithesis of competition.
    We dismiss as misplaced the claims that Order No. 888's stranded 
cost recovery mechanism is a tying arrangement that is a per se 
antitrust violation that cannot be justified by reference to the 
reasons for the restraint or the expected ancillary benefits. Any 
``tying'' that might result from the Rule is by regulatory order, not 
through monopoly power, and is justified as a means to avoid unfair 
cost shifting and to achieve the pro-competitive benefits of the Rule. 
As we stated in Order No. 888, the purpose and effect of the stranded 
cost recovery mechanism that we approve are to facilitate the 
transition to competitive wholesale power markets, not to prevent a 
generation customer of a utility from being able to reach alternative 
suppliers through its former supplier's transmission.<SUP>559
---------------------------------------------------------------------------

    \559\ Cf. Eastman Kodak Company v. Image Technical Services, 
Inc., 504 U.S. at 486-87 (Scalia, J. dissenting) (``Per se rules of 
antitrust illegality are reserved for those situations where logic 
and experience show that the risk of injury to competition from the 
defendant's behavior is so pronounced that it is needless and 
wasteful to conduct the usual judicial inquiry into the balance 
between the behavior's procompetitive benefits and its 
anticompetitive costs.'').
---------------------------------------------------------------------------

    To be sure, imposing a stranded cost charge might, in the short 
run, make some customers indifferent to whether they stay with their 
current suppliers and avoid stranded costs, or go with new suppliers 
but pay stranded costs to the former suppliers.<SUP>560 There is no 
question that, without the stranded cost recovery mechanism, some 
customers would be far more likely to switch to lower-cost suppliers 
and enjoy sooner the benefits of a competitive power market. But, as 
detailed in Order No. 888, such an approach may result in higher costs 
for other customers. We thus have had to balance the potential for 
earlier benefits for some customers against other public interest 
considerations, most particularly the need to provide a fair mechanism 
by which utilities can recover the costs of past investments under 
traditional regulatory concepts of prudently incurred costs and cost 
causation. The result is not to deny competitive advantages, but only 
to delay their full realization for some customers.
---------------------------------------------------------------------------

    \560\ In effect, we recognize that we may have to endure some 
short-term delay in the transition from monopoly suppliers to 
competitive suppliers. However, this is not anticompetitive; it is a 
necessary part of a scheme that is procompetitive overall. See 
American Gas Association v. FERC, 888 F.2d 136, 149 (D.C. Cir. 1989) 
(``If conditioning access is a necessary part of a scheme that is 
procompetitive overall, however, then it does not violate the NGPA 
[Natural Gas Policy Act] even if it may seem to be anticompetitive 
when viewed in isolation.'').
---------------------------------------------------------------------------

    In any event, we do not believe that the Commission-imposed 
mechanism of allowing the utility to recover stranded costs from the 
departing customer through its transmission rates falls within the 
category of an illegal tying arrangement under the antitrust laws. As 
the Supreme Court has defined it, ``[a] tying arrangement is `an 
agreement by a party to sell one product but only on the condition that 
the buyer also purchases a different (or tied) product, or at least 
agrees that he will not purchase that product from any other 
supplier.''' <SUP>561
---------------------------------------------------------------------------

    \561\ Eastman Kodak Company v. Image Technical Services, 504 
U.S. 451, 461 (1992).
---------------------------------------------------------------------------

    Here there is no ``tying'' of ``products.'' <SUP>562 Instead, the 
Rule provides a mechanism for recovering costs associated with a prior 
contract. We have not adopted a rule under which a customer may 
purchase transmission from a utility only on the condition that the 
customer also purchases a different product, namely, power, from the 
utility.<SUP>563 To the contrary, the Commission, through the Order No. 
888 open access transmission requirement, is attempting to provide the 
customer with the opportunity to obtain unbundled transmission from a 
former supplying utility as a means to reach a new generation supplier. 
Whatever else, the stranded costs are not charges for ``products'' and 
thus there is no ``tying'' in the conventional sense. At best, there is 
only a condition: in obtaining unbundled transmission, the customer 
must also pay appropriate costs stranded by its use of Commission-
required transmission access.
---------------------------------------------------------------------------

    \562\ A ``service'' can constitute a ``product'' for purposes of 
a tying analysis. See Eastman Kodak Company v. Image Technical 
Services, Inc., 504 U.S. at 462.
    \563\ The Rule requires all transmission customers to purchase 
at least some reactive supply and voltage control service from the 
transmission provider. However, the Commission found that the cost 
of such services is ``part of the cost of basic transmission 
service.'' FERC Stats. & Regs. at 31,706; mimeo at 209. That is, it 
is a necessary part of providing the service and thus, by 
definition, not a ``tying.''
---------------------------------------------------------------------------

    Finally, it is not clear how often departing customers will be 
obligated to pay stranded costs. Stranded cost recovery is by no means 
guaranteed under the Rule, nor is it clear what portion of a utility's 
uneconomic investment will be recoverable as stranded costs. Even when 
a utility is able to meet the evidentiary standard and the Commission 
approves imposition of a stranded cost charge, the customer is free to 
pay off its obligation immediately. If it chooses to pay off the 
stranded cost obligation over time, that charge would not be imposed 
indefinitely on the customer. We have limited the scope of contracts 
and costs for which utilities may seek stranded cost recovery. This 
limitation--to certain contracts and demonstrated costs--in our 
judgment fairly allocates between utility and customer the

[[Page 12389]]

burdens and benefits of open access transmission.
    Nor is it true that the Rule does not allow customers 
``meaningful'' access to alternative power suppliers. The Final Rule 
pro forma tariff contains terms and conditions ensuring the provision 
of non-discriminatory transmission service. The requirements that a 
public utility take service under its own tariff for wholesale sales 
and purchases, adopt a non-discriminatory transmission information 
network, and separate power marketing and transmission functions 
further ensure non-discrimination and remove constraints to fair 
competition. The result is meaningful access to alternative suppliers 
that goes far beyond what was offered in the transmission tariff under 
review in Cajun.
    Contrary to the claims of some, the Open Access Rule does not 
guarantee that a utility may sell its power at market-based rates. The 
open access compliance tariff required by Order No. 888 does mitigate 
transmission market power.<SUP>564 However, the Commission's Rule does 
not generically grant market-based rate authority to utilities that 
file compliance tariffs. Utilities must still demonstrate on a case-by-
case basis that they not only have mitigated transmission market power 
but also do not have market power in generation <SUP>565 or other 
barriers to entry.
---------------------------------------------------------------------------

    \564\ Such tariff is a condition, but not the sole condition, 
for market-based rates. See, e.g., Delmarva Power & Light Company, 
et al., 76 FERC para. 61,331 (1996); accord Southern Company 
Services, Inc., 71 FERC para. 61,392 at 62,536 (1995); Heartland 
Energy Services, Inc., et al., 68 FERC para. 61,223 at 62,059-60 
(1994).
    \565\ A seller requesting market-based rates is not required to 
demonstrate any lack of generation market power with respect to 
sales from capacity for which construction commenced on or after the 
effective date (July 9, 1996) of the Rule. 18 CFR 35.27(a). However, 
if specific evidence is presented by an intervenor that a seller 
requesting market-based rates for sales from new generating capacity 
nevertheless has generation dominance, the Commission will evaluate 
whether the seller has generation dominance with respect to the new 
capacity. FERC Stats. & Regs. at 31,657; mimeo at 65-66.
---------------------------------------------------------------------------

    Notwithstanding the objections by some commenters that the stranded 
cost procedures of Order No. 888 fail to provide certainty in the 
computation of stranded cost charges, we believe that directly 
assigning stranded costs to departing generation customers using the 
revenues lost formula is the fairest and most efficient way to balance 
the competing interests of those involved. The alternatives that we 
considered (an up-front broad-based approach or an as-realized broad-
based approach) have significant disadvantages and are extensively 
discussed in Order No. 888.<SUP>566 Following a careful evaluation of 
the alternatives, we concluded that a revenues lost formula to 
calculate a customer's stranded cost obligation is more reasonable and 
provides greater certainty than would other approaches, such as those 
that rely on broad-based surcharge schemes that impose costs that may 
never be incurred or those that result in widely fluctuating 
transmission rates.<SUP>567 As we stated in Order No. 888, while we 
recognize that some commenters oppose the revenues lost approach as 
imprecise, any ratemaking method that relies on estimates will be 
subject to forecasting error.<SUP>568 Nevertheless, we have gone to 
great lengths to provide specificity with respect to the calculation of 
the components of the formula.
---------------------------------------------------------------------------

    \566\ See FERC Stats. & Regs. at 31,797-800; mimeo at 477-85.
    \567\ Under the revenues lost approach, a customer's stranded 
cost obligation is calculated by subtracting the competitive market 
value of the power the customer would have purchased (on an average 
annual basis) from the average annual revenues that the customer 
would have paid had it remained on the utility's generation system, 
and multiplying the result by the period of time the utility 
reasonably could have expected to serve the customer beyond the 
contract termination but for the open access required under Order 
No. 888. See FERC Stats. & Regs. at 31,839-45 for a detailed 
explanation of the various components of the formula.
    \568\ FERC Stats. & Regs. at 31,841; mimeo at 600-01.
---------------------------------------------------------------------------

    In response to those commenters that argue that Order No. 888's 
stranded cost procedures will add costs of potential deal-killing 
magnitude to any power supply acquisition considered by a customer, we 
believe that, to the contrary, use of the formula will narrow the scope 
of disputes over the calculation of stranded costs, lend precision to 
the stranded cost amount it produces, and provide certainty to 
departing generation customers with respect to their stranded cost 
obligations.
    APPA and ELCON object to the Commission's reference to Western 
Resources as a case affirming the Commission's ability to allow 
stranded cost recovery. Notwithstanding their efforts to distinguish 
Western Resources (for example, as a filed rate doctrine case, not a 
stranded cost case, and as a case involving no allegation of 
anticompetitive conduct), they have failed to make a convincing 
argument that our description of that case as ``confirm[ing] the 
validity of Commission-imposed stranded cost recovery mechanisms in the 
transition to competitive markets'' <SUP>569 is not accurate. The case 
depends upon the validity of the Commission's decision to allow the 
recovery of costs stranded in the transition of the natural gas 
industry to a competitive market and supports the Commission's ability 
to allow stranded cost recovery in general. The same court, in United 
Distribution Companies, has recently confirmed the Commission's ability 
to allow the recovery of costs stranded in the transition to 
competitive markets, limiting its concerns to issues about ``how'' 
stranded costs should be recovered and from whom.<SUP>570
---------------------------------------------------------------------------

    \569\ FERC Stats. & Regs. at 31,793; mimeo at 464-65.
    \570\ 88 F.3d at 1129, 1182-83.
---------------------------------------------------------------------------

3. Responsibility for Wholesale Stranded Costs (Whether To Adopt Direct 
Assignment to Departing Customers)
    In Order No. 888, the Commission concluded that direct assignment 
of stranded costs to the departing wholesale generation customer 
through either an exit fee <SUP>571 or a surcharge on transmission is 
the appropriate method for recovery of such costs. We concluded that 
the departing generation customer (and not the remaining generation or 
transmission customers or shareholders) should bear the legitimate and 
prudent obligations that the utility undertook on that customer's 
behalf. In reaching this decision, we carefully weighed the arguments 
supporting direct assignment of stranded costs against those supporting 
the broad-based approach of spreading stranded costs to all 
transmission users of a utility's system. After a detailed review of 
the advantages and disadvantages of each approach, we concluded that, 
on balance, direct assignment is the preferable approach for both legal 
and policy reasons.<SUP>572 Our primary considerations were that direct 
assignment is consistent with the well-established principle that the 
one who has caused a cost to be incurred should pay that cost and that 
it will result in a more accurate determination of a utility's stranded 
costs than would an up-front, broad-based transmission surcharge.
---------------------------------------------------------------------------

    \571\ We defined ``exit fee'' as the charge that will be payable 
by a departing generation customer upon the termination of its 
requirements contract with a utility (if the utility is able to 
demonstrate that it reasonably expected to continue serving the 
customer beyond the term of the contract), whether payable in a 
lump-sum payment or an amortization of a lump-sum payment. (The same 
charge also can be paid as a surcharge on the customer's 
transmission rate.)
    \572\ FERC Stats. & Regs. at 31,797-800; mimeo at 477-85.
---------------------------------------------------------------------------

    The Commission also acknowledged that the direct assignment 
approach adopted in Order No. 888 is different from the approach taken 
for the natural

[[Page 12390]]

gas industry. We explained why we believe that difference to be 
justified by pointing out a number of differences between the 
transition of the electric industry to an open transmission access, 
competitive industry and the transition of the natural gas industry to 
open access transportation service by interstate natural gas 
pipelines.<SUP>573 We also declined to require a utility seeking 
stranded cost recovery to shoulder a portion of its stranded costs on 
the basis that such a requirement would be a major deviation from the 
traditional principle that a utility should have a reasonable 
opportunity to recover its prudently incurred costs, and explained why 
we applied a different approach in the gas area.<SUP>574
---------------------------------------------------------------------------

    \573\ FERC Stats. & Regs. at 31,800-802; mimeo at 485-90.
    \574\ FERC Stats. & Regs. at 31,802-03; mimeo at 490-92.
---------------------------------------------------------------------------

Rehearing Requests Opposing Full Recovery From Departing Customers

    A number of entities submit that the Commission has not adequately 
explained its decision not to require some utility sharing of stranded 
costs when the utility can satisfy the reasonable expectation criteria. 
They object that the Commission did not meaningfully consider the 
arguments made by commenters concerning utility responsibility (such as 
poor management decisions) for stranded costs.<SUP>575
---------------------------------------------------------------------------

    \575\ E.g., ELCON, IL Industrials, San Francisco, Nucor. Other 
entities that urge the Commission to require shareholders to 
shoulder a portion of the utility's stranded costs include Central 
Illinois Light, AR Com, American Forest & Paper, Nucor, and 
Occidental Chemical. American Forest & Paper and Nucor suggest that 
full recovery destroys incentives to mitigate. Several entities also 
support spreading the costs to all of the utility's customers. E.g., 
American Forest & Paper, Central Illinois Light, AR Com.
---------------------------------------------------------------------------

    ELCON argues that departing customers are not the sole cause of 
stranded costs. IL Industrials submits that the statement in the Rule 
that utility shareholders ``'had no responsibility for causing the 
legitimate, prudent and verifiable costs to be incurred''' is 
untrue.<SUP>576 It argues that although utilities may have had a legal 
obligation to serve and meet projected demands, how the utility chose 
to meet those obligations was under the utility's control. IL 
Industrials asserts that shareholders should bear some of the risk 
associated with the decisions of their management that were less than 
optimal. At a minimum, IL Industrials argues that the Commission should 
consider on a case-by-case basis (when it determines whether a utility 
has incurred legitimate and verifiable stranded costs) whether some 
amount of stranded costs should be shared with shareholders.
---------------------------------------------------------------------------

    \576\ IL Industrials at 4-6 (citing Order No. 888, mimeo at 491-
92).
---------------------------------------------------------------------------

    NASUCA challenges the Commission's statement in Order No. 888 that 
requiring a utility to shoulder a portion of its stranded costs ``would 
be a major deviation from the traditional principle that a utility 
should have a reasonable opportunity to recover its prudently incurred 
costs.'' <SUP>577 It contends that there is no constitutionally 
guaranteed right of recovery of all prudent investment.<SUP>578 NASUCA 
further asserts that full recovery of uneconomic investment is not the 
norm. It submits that the Commission has rejected utility demands for 
full recovery of cancelled electric generation facilities.<SUP>579
---------------------------------------------------------------------------

    \577\ FERC Stats. & Regs. at 31,802; mimeo at 490.
    \578\ NASUCA cites in support of its position Covington & 
Lexington Turnpike Road Company v. Sandford, 164 U.S. 578 (1896); 
Market Street Railway Company v. Railroad Commission, 324 U.S. 548 
(1945) (Market Street); Duquesne Light Company v. Barasch, 488 U.S. 
299, 315-16 (1989).
    \579\ NASUCA cites in support of its position New England Power 
Company, 8 FERC para. 61,054 (1979), aff'd sub nom. NEPCO Municipal 
Rate Committee v. FERC, 668 F.2d 1327 (D.C. Cir. 1981), cert. 
denied, 457 U.S. 1117 (1982). NASUCA states that in that case, 
prudently incurred plant investment was abandoned because changing 
circumstances rendered the investment uneconomic; the Commission 
provided for a ten-year amortization of the plant investment, with 
no return on the unamortized balance. NASUCA says that this 
precedent demonstrates that the ``regulatory compact'' does not 
require full cost recovery.
---------------------------------------------------------------------------

    San Francisco cites Market Street as support for the proposition 
that the risk of unmarketability should fall, in whole or in part, on 
utility shareholders who knew of competitive risks and who have been 
compensated for those risks through rates of return.
     A number of parties object that the Commission, in declining to 
require some shareholder sharing of stranded costs, is allowing the 
electric utility industry to claim more generous recoveries under Order 
No. 888 than it allowed the gas industry, and that it has provided no 
adequate rationale for this difference in treatment.<SUP>580 San 
Francisco states that although the Rule attempts to distinguish 
shareholder sharing in the natural gas industry ``as an extraordinary 
measure given the nature of the take-or-pay problem and the prevailing 
environment at that time,'' <SUP>581 the Commission has not identified 
how the nature of the take-or-pay problem was any more 
``extraordinary'' than the nature of stranded costs in electric 
restructuring, or explain its reference to ``the prevailing environment 
at that time.''
---------------------------------------------------------------------------

    \580\ E.g., Central Illinois Light, Occidental Chemical.
    \581\ FERC Stats. & Regs. at 31,802; mimeo at 491.
---------------------------------------------------------------------------

    Occidental Chemical submits that the Commission's decision not to 
allocate a portion of stranded costs to utilities on cost causation 
grounds contradicts the Commission's actions in Order No. 636, in which 
it required interruptible and new shippers, as beneficiaries of open 
access, to share in the costs of the transition.<SUP>582 Central 
Illinois Light states that the Commission should allow partial recovery 
of stranded costs and thereby correct key differences in the 
Commission's responses to gas and electric transition costs.<SUP>583
---------------------------------------------------------------------------

    \582\ Occidental Chemical argues that requiring gas customers to 
choose their suppliers during an open season enabled the pipelines 
to place a dollar value on their take-or-pay obligations. Shippers 
thus knew at the outset what their gas supply realignment (GSR) 
surcharge would be and could negotiate with other suppliers 
accordingly. Occidental Chemical says that most pipelines have 
already recouped their GSR costs and have made the transition to a 
competitive supply market in under three years. It argues that, on 
the other hand, allowing electric stranded costs to be recovered 
over an indefinite period will blunt the pro-competitive effect of 
Order No. 888.
    \583\ Central Illinois Light supports a recovery mechanism that 
would allow utilities to allocate stranded costs to requirements 
customers on a demand basis and to all transmission customers on a 
commodity basis. It argues that this would recognize the greater 
cost responsibility of requirements customers, recognize the 
benefits obtained by all transmission customers from open access, 
and reduce the charges to all customers to a more reasonable level.
---------------------------------------------------------------------------

    Occidental Chemical also objects that the Commission failed to 
address the merits of its suggestion that the Commission grant a 
utility a presumption of prudence in return for absorbing a percentage 
of its stranded costs.
    ELCON, in a supplement to its rehearing request,<SUP>584 submits 
that the D.C. Circuit's remand in United Distribution Companies of the 
aspect of Order No. 636 that allocated 100 percent of gas supply 
realignment costs to customers and none to pipelines has implications 
for the Commission's decision in Order No. 888 to allocate 100 percent 
of stranded costs to departing customers without any shareholder 
sharing of the costs. ELCON suggests that although the D.C. Circuit 
indicated that a finding of threat to the financial viability of the 
pipeline sector might justify such allocation, there is no evidence in 
the record in the Order No. 888 proceeding, and the Commission has made 
no finding, that wholesale stranded cost recovery jeopardizes the 
financial viability of the utility sector. It

[[Page 12391]]

adds that, to the extent the Commission relies on strict cost causation 
principles in Order No. 888, it is not clear how departing wholesale 
customers who signed contracts in 1985 could have ``caused'' utilities 
to incur uneconomic assets such as expensive nuclear facilities that 
were planned and ordered in the 1970s.
---------------------------------------------------------------------------

    \584\ We will accept this pleading as a motion for 
reconsideration, not as a request for rehearing, because it was not 
filed within the 30-day statutory period for rehearing requests. See 
16 U.S.C. Sec. 825l(a).
---------------------------------------------------------------------------

Commission Conclusion

    As we explained in Order No. 888, we decided not to require a 
utility meeting the requirements for stranded cost recovery to shoulder 
a portion of its stranded costs because such a requirement would be a 
major deviation from the traditional principle that a utility should 
have a reasonable opportunity to recover its prudently incurred 
costs.<SUP>585 Our decision (which allows assignment of legitimate, 
prudent and verifiable stranded costs to departing requirements 
generation customers, not to shareholders or other customers of the 
utility) also follows the cost causation principle that has been 
fundamental to our regulation since 1935.<SUP>586 It is important, in 
this regard, to distinguish between assuring recovery of all uneconomic 
costs (which Order No. 888 does not do) and providing an opportunity 
for recovery where the evidentiary requirements of the Rule are met.
---------------------------------------------------------------------------

    \585\ FERC Stats. & Regs. at 31,802; mimeo at     490-91.
    \586\ In response to ELCON's argument that it is not clear how 
departing wholesale customers who signed contracts in 1985 could 
have ``caused'' utilities to incur uneconomic assets such as 
expensive nuclear facilities that were planned and ordered in the 
1970s, we note that customers taking requirements service generally 
pay an allocated share of total embedded costs, including the cost 
of investments made before the customer began service. This pricing 
principle is consistent with the method that Order No. 888 adopts 
for calculating a departing customer's stranded cost obligation. The 
revenues lost approach is not an asset-by-asset approach. Instead, 
it is an approach that looks at a utility's current rates, which are 
based on all the utility's assets, which may include both high cost 
and low cost generating facilities of various ages, and relies on 
the presumption that the fixed costs allocated to departing 
customers under their current rates are properly assignable to them. 
Thus, if a utility is able to demonstrate that it had a reasonable 
expectation of continuing to serve the customer after the contract 
term, the customer's stranded cost obligation would be computed 
based on the average annual revenues that the customer would have 
paid had it remained a customer of the utility; the calculation of 
stranded costs would not be tied to any particular investments that 
the utility made in a particular unit. As we explain in Section 
IV.J.9 below, the use of present annual revenues as the basis for 
the stranded cost calculation is based, among other things, on the 
presumption that present rates include all just and reasonable costs 
of providing service.
---------------------------------------------------------------------------

    Allowing full recovery of stranded costs under Order No. 888 is not 
equivalent to allowing 100 percent recovery of the costs of all 
uneconomic assets. A utility may have uneconomic assets for a variety 
of reasons, including a decline in load, customer shifts to natural 
gas, customer energy conservation, loss of a large industrial customer, 
customer self-generation, and a customer gaining transmission access 
through another utility's transmission system. The Rule does not 
provide for the recovery of the costs of such uneconomic assets.
    Instead, the Rule defines a discrete set of uneconomic costs that 
are stranded by FPA section 211 or Order No. 888 transmission service 
(when a customer uses the former supplying utility's transmission 
system to reach a new supplier) for which utilities may seek recovery. 
However, even as to this set of costs the Rule does not guarantee 100 
percent recovery. To be eligible to recover such costs, a utility must 
satisfy the reasonable expectation test set forth in Order No. 888. 
Even then, the utility will be eligible to recover only costs that are 
legitimate, prudent and verifiable.
    In response to those entities that argue that departing customers 
are not the sole cause of stranded costs and that poor management 
decisions may be partly to blame, we reiterate that a determination 
that a utility has a reasonable expectation of continuing to serve a 
customer would not, in all circumstances, mean that costs incurred by 
the utility were prudent. As we said in Order No. 888, we cannot make a 
blanket assumption that all claimed stranded costs were prudently 
incurred. We explained that prudence of costs, depending upon the facts 
in a specific case, may include different things, such as prudence in 
operation and maintenance of a plant, and the utility's ongoing 
obligation to exercise prudence in retaining existing investments and 
power purchase contracts and in entering into new ones.<SUP>587 We 
clarified, however, that we do not intend to relitigate the prudence of 
costs previously recovered.
---------------------------------------------------------------------------

    \587\ FERC Stats. & Regs. at 31,850; mimeo at 626.
---------------------------------------------------------------------------

    Thus, to the extent that costs have not been previously recovered 
by a utility, and depending upon the facts presented, a customer from 
whom a utility is seeking to recover stranded costs may be able to 
challenge the prudence of those costs. If such prudence challenge is 
successful, then the utility would not be entitled to recovery of the 
imprudently incurred costs, through stranded cost recovery or 
otherwise. We believe that this fully addresses the concerns of those 
entities that contend that departing customers should not be 
responsible for costs that result from poor management decisions or 
other actions by the utility.<SUP>588
---------------------------------------------------------------------------

    \588\ Whether poor management decisions or other actions are 
imprudent would be decided on a case-by-case basis. See, e.g., New 
England Power Company, Opinion No. 231, 31 FERC para. 61,047 at 
61,081-84, reh'g denied, Opinion No. 231-A, 32 FERC para. 61,112 
(1985), aff'd sub nom., Violet v. FERC, 800 F.2d 280 (1st Cir. 
1986); Minnesota Power & Light Company, Opinion No. 86, 11 FERC 
para. 61,312 at 61,644-45, order on reh'g, 12 FERC para. 61,264 
(1980). However, a utility's costs are presumed prudent and a person 
challenging such costs would have the burden of going forward with 
evidence that raises a serious doubt as to prudence. Id., 11 FERC at 
61,645.
---------------------------------------------------------------------------

    As we explained in Order No. 888, our decision not to require 
utilities to shoulder a portion of their stranded costs is based on the 
traditional principle that a utility should have a reasonable 
opportunity to recover its prudently incurred costs. <SUP>589 NASUCA's 
reliance on the Commission's cancelled plant policy to support its 
argument that full recovery of uneconomic investment is not the norm is 
misplaced. The Commission's cancelled plant policy, which allows a 
utility to recover 50 percent of its prudently-incurred investment in a 
cancelled or abandoned plant, relates only to plants that are cancelled 
or abandoned prior to entering commercial service and thus prior to 
becoming used and useful.<SUP>590 The Commission has taken a different 
approach in the case of electric generating plants that are prematurely 
shut down after having been in commercial operation for a number of 
years. In the latter instance (which more closely resembles the type of 
costs for which a utility might seek recovery under Order No. 888 than 
does the cancelled plant before operation scenario), the Commission has 
allowed 100 percent recovery of prudently-incurred unamortized 
investment.<SUP>591
---------------------------------------------------------------------------

    \589\ See, e.g., Maryland v. Louisiana, 451 U.S. 725, 748 
(1981); Office of Consumers' Counsel v. FERC, 914 F.2d 290, 292 
(D.C. Cir. 1990); City of New Orleans, Louisiana v. FERC, 67 F.3d 
947, 954 (1st Cir. 1995).
    \590\ See New England Power Company, Opinion No. 295, 42 FERC 
para. 61,016, reh'g denied in part and granted in part, Opinion No. 
295-A, 43 FERC para. 61,285 (1988). We note that the Supreme Court 
case on which NASUCA relies to support its argument that there is no 
constitutionally guaranteed right of recovery of all prudent 
investment, Duquesne, also involved electrical generating facilities 
that were planned but never built. See 488 U.S. 299 (1989).
    \591\ See Yankee Atomic Electric Company, Opinion No. 390, 67 
FERC para. 61,318, (Yankee Atomic), reh'g denied, 68 FERC para. 
61,364 (1994), remanded on other grounds, Town of Norwood, 
Massachusetts v. FERC, 80 F.3d 526 (D.C. Cir. 1996), offer of 
settlement accepted, letter dated January 30, 1997, Docket No. ER92-
592-005. This case involved a nuclear plant that had been in 
operation for over 30 years. In affirming the Commission's decision 
to allow full recovery and not to apply Opinion No. 295's recovery 
rule for plants abandoned before operation, the court explained:
    Although ratepayers generally `bear the expense of depreciation' 
and although investors generally `are entitled to recoup from 
consumers the full amount of their investment in depreciable assets 
devoted to public service,' [citations omitted] Opinion No. 295 
makes a logical exception to this full recovery rule for plants 
abandoned before operation; in such cases, ratepayers have not 
benefitted from the plant. The situation here is quite different. 
Because customers have benefitted from the operation of the plant 
for over 30 years, and because ceasing plant operations will benefit 
customers by lowering rates, such an exception is unwarranted. 
Moreover, applying Opinion No. 295's recovery rule would not, as it 
would in the case of a plant that never began operations, promote 
economic efficiency.'' 80 F.3d at 532.
    In Yankee Atomic, the Commission also allowed recovery of 100 
percent of construction work in progress and of post-shutdown O&M 
expenditures.

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

[[Page 12392]]

    San Francisco's and NASUCA's reliance on Market Street is also 
distinguishable. That case involved an industry (street railway) that 
had been rendered economically obsolete by market forces. The electric 
industry today, in contrast, is clearly not obsolete. Moreover, the 
costs that Order No. 888 gives a utility an opportunity to recover even 
in the face of market forces would not become stranded but for 
statutory and regulatory changes.
    A number of parties contend that the Commission has not provided an 
adequate rationale for its different treatment of shareholder sharing 
in the natural gas industry. ELCON also relies on the D.C. Circuit's 
remand in United Distribution Companies of Order No. 636's holding that 
pipelines could recover 100 percent of their gas supply realignment 
(GSR) costs. After further review of this matter in light of the 
Court's decision in United Distribution Companies, we reaffirm that, 
even though the Commission permitted pipelines to recover take-or-pay 
costs based on ``cost spreading'' and ``value of service'' principles, 
stranded electric utility costs should be recovered based on 
traditional cost causation principles. This is because, despite the 
fact that both sets of costs are incurred in connection with a 
transition to unbundled, open access service, there are also 
substantial differences between the circumstances surrounding the two 
industries' incurrence of their respective transition costs.
    The pipelines' take-or-pay problems began before the Commission 
initiated open access transportation in Order No. 436. The severe gas 
shortages of the 1970s led to enactment of the Natural Gas Policy Act 
(NGPA), which initiated a phased decontrol of most new gas prices and 
established ceiling prices for controlled gas, including incentive 
prices for price-controlled new gas higher than the ceiling prices 
previously established by the Commission under the NGA.<SUP>592 To 
avoid future shortages, pipelines then entered into long-term take-or-
pay contracts at the high prices made possible by the NGPA, and those 
high prices stimulated producers to greatly increase exploration and 
drilling.<SUP>593 When demand unexpectedly fell and supply increased, 
the pipelines found themselves contractually bound to take or pay for 
high-priced gas which they could not sell. Even before Order No. 436 
issued in October 1985, pipeline take-or-pay exposure was approaching 
$10 billion.<SUP>594 In 1986, as pipelines were just beginning to 
implement open access transportation under Order No. 436 and before the 
August 1987 issuance of Order No. 500, the pipelines' outstanding 
unresolved take-or-pay liabilities peaked at $10.7 billion.<SUP>595
---------------------------------------------------------------------------

    \592\ Order No. 500-H, Regulations Preambles 1986-1990, FERC 
Stats. & Regs. para. 30,867 at 31,509 (1989).
    \593\ Id. at 31,509-10.
    \594\ Id. at 31,513.
    \595\ Id.
---------------------------------------------------------------------------

    The Commission and the industry had never previously faced a take-
or-pay problem of this nature or magnitude. In earlier times, pipelines 
had made take-or-pay payments to particular producers, and the 
Commission had a policy of permitting such payments to be included in 
rate base and then recovered as a gas cost when the pipeline later took 
the gas under make-up provisions in the contract.<SUP>596 By 1983, 
however, the pipelines could not manage their take-or-pay problems, and 
stopped honoring the bulk of their take-or-pay liabilities.<SUP>597 
They then sought settlements with the producers to reform or terminate 
the uneconomic take-or-pay contracts and to resolve outstanding take-
or-pay liabilities. Because pipelines had never previously incurred 
significant take-or-pay settlement costs, the Commission had no policy 
concerning whether and how pipelines were to recover those costs. The 
Commission commenced establishing such a policy in an April 1985 policy 
statement,<SUP>598 just six months before Order No. 436. When Order No. 
500 issued, few take-or-pay settlement costs had yet been included in 
pipelines' rates. However, since the pipelines' outstanding take-or-pay 
liabilities were in the neighborhood of $10 billion, it was clear that 
pipelines would incur massive costs in their settlements with 
producers.
---------------------------------------------------------------------------

    \596\ Regulatory Treatment of Payments Made in Lieu of Take-or-
Pay Obligations, Regulations Preambles 1982-85, FERC Stats. & Regs. 
para. 30,637 at 31,301 (1985).
    \597\ In Order No. 500-H, the Commission found that, although 
pipelines incurred total take-or-pay exposure over the period 
January 1, 1983 through June 30, 1987 of over $24 billion, they made 
take-or-pay payments totalling only $.7 billion. Order No. 500-H, 
Regulations Preambles 1986-1990 para. 30,867 at 31,514.
    \598\ Regulatory Treatment of Payments Made in Lieu of Take-or-
Pay Obligations, Regulations Preambles 1982-85, FERC Stats. & Regs. 
para. 30,637 (1985).
---------------------------------------------------------------------------

    In short, when the Commission first addressed the issue of how to 
allocate take-or-pay settlement costs in Order No. 500, it did so under 
the shadow of the pipelines' vast outstanding take-or-pay exposure. The 
essential problem, therefore, was to decide which customers' rates 
should be raised to reflect the billions of dollars of take-or-pay 
settlement costs that the pipelines were incurring, but that the 
pipelines had still not filed to recover. To have allocated those costs 
solely to any one segment of the industry would have imposed a crushing 
new burden on that segment. For example, if the Commission had 
allocated the take-or-pay settlement costs entirely to bundled sales 
customers who chose to convert to transportation-only service, those 
customers would have ended up far worse off than if they remained as 
bundled sales customers.
    As a result of all these facts, the fundamental premise of Order 
No. 500 was, as the Court expressed it in KN Energy, that ``the 
extraordinary nature of this problem requires the aid of the entire 
industry to solve it.'' <SUP>599 In order to accomplish this result, 
Order No. 500 established an equitable sharing mechanism for pipelines 
to use in recovering their take-or-pay settlement costs as an 
alternative to recovery through their commodity sales rates. Relying on 
``cost spreading'' and ``value of service'' principles, the Commission 
permitted pipelines to allocate their take-or-pay settlement costs 
among all the pipelines' customers. The Commission also required the 
pipelines using the equitable sharing mechanism to absorb a portion of 
the costs in return for the ability to recover an equal portion through 
a fixed charge. Importantly, pipelines using the equitable sharing 
mechanism and agreeing to absorb a portion of the costs were given a 
presumption that their take-or-pay settlement costs were prudent. Those 
who did not choose to avail themselves of the sharing/absorption 
mechanism could still file for recovery of take-or-pay costs pursuant 
to the traditional ratemaking methodology. Because the pipelines' cash 
flow problems were so severe and they could not reasonably expect to 
recover their costs through their sales

[[Page 12393]]

rates, they readily availed themselves of the special mechanism, with 
its presumption of prudence, rather than the more protracted 
traditional ratemaking option.<SUP>600
---------------------------------------------------------------------------

    \599\ 968 F.2d 1295, 1301 (D.C. Cir. 1992).
    \600\ By contrast, Order No. 888 does not provide a presumption 
of prudence for utilities' stranded cost recovery proposals. Once 
again, the more traditional concept that the utility must prove 
costs were prudently incurred will apply.
---------------------------------------------------------------------------

    The Court in KN Energy upheld the Commission's use of cost 
spreading in connection with the allocation of take-or-pay costs among 
a pipeline's open access customers.<SUP>601 The Court held that ``the 
ratemaking rationales of Order No. 500 can be reconciled with the NGA, 
given the unusual circumstances surrounding the take-or-pay problem, 
and the limited nature--both in time and scope--of the Commission's 
departure from the cost-causation principle.'' <SUP>602 The Court 
emphasized that ``[w]e hold only--and quite narrowly--that in the 
context of Order No. 500 the Commission has not betrayed its 
obligations to the NGA or precedent by employing these ratemaking 
principles in its attempt to bring closure to the take-or-pay drama.'' 
<SUP>603
---------------------------------------------------------------------------

    \601\ The Court did not review the Order No. 500/528 requirement 
that pipelines absorb a share of the take-or-pay costs. See AGA v. 
FERC, 888 F.2d 136, 152 (D.C. Cir. 1989), and AGA v. FERC, 912 F.2d 
1496, 1519 (D.C. Cir. 1990), cert. denied, 498 U.S. 1084 (1991), 
both holding the absorption requirement not ripe for review.
    \602\ KN Energy, 968 F.2d at 1301.
    \603\ Id. at 1302.
---------------------------------------------------------------------------

    The unusual circumstances that justified the departure from cost 
causation principles in Order Nos. 500/528 are not present in the 
electric industry. In Order No. 888's discussion of the Commission's 
decision not to order any generic abrogation of existing requirements 
and transmission contracts between electric utilities and their 
customers, we have already pointed out:

    At the time the Commission addressed this situation in the 
natural gas industry, it was faced with shrinking natural gas 
markets, statutory escalations in natural gas prices under the 
Natural Gas Policy Act, and increased production of gas. In other 
words, there was a market failure in the industry. * * * In 
contrast, there is no such market failure in the electric 
industry.<SUP>[604]

    \604\ FERC Stats. & Regs. at 31,664; mimeo at 84.
---------------------------------------------------------------------------

    The electric utility costs potentially stranded by Order No. 888 
are fixed costs arising from the utility's electric generation 
business, including, for example, depreciation expense associated with 
the utilities' own generation facilities and a return on the original 
cost of its investment in those facilities. They also include costs 
associated with mandatory QF purchase contracts. Unlike take-or-pay 
settlement costs, these costs are not an extraordinary expense that the 
Commission has never previously encountered. Rather, the stranded 
electric costs that are subject to the direct assignment provisions of 
Order No. 888 are ordinary costs that have always been, and are 
currently, included in the utility's rates for electric generation 
approved by the Commission. And there is no pre-existing industry-wide 
market failure. Thus, we are not confronted at the start of the 
electric open access program with a vast outstanding cost not currently 
reflected in the electric utilities' rates, as we were at the start of 
the natural gas open access program.
    Therefore, unlike the situation with the natural gas industry, 
stranded electric utility costs can be allocated among customers based 
upon traditional cost causation principles without imposing inequitable 
and unreasonable burdens on particular customer classes. Direct 
assignment to departing requirements generation customers through the 
stranded cost recovery mechanism contained in the Rule is consistent 
with the traditional cost causation principle because it recognizes the 
link between the incurrence of stranded costs and the decision of a 
particular generation customer to use open access transmission on the 
utility's system to leave the utility's generation system and shop for 
power, and bases the utility's ability to recover stranded costs on its 
ability to demonstrate that it incurred costs with the reasonable 
expectation that the customer would remain on its generation system 
beyond the term of the contract. The stranded costs are measured as the 
difference between revenues the utility would have recovered from the 
customer and the market value of the utility's power.
    In essence, therefore, all that the direct assignment provisions of 
Order No. 888 require is that certain customers (those whom a utility 
is able to demonstrate it reasonably expected to continue serving 
beyond the contract term) who convert to transmission-only service 
continue, for a period, to bear certain generation costs that they were 
previously bearing. This helps to minimize immediate cost shifts to the 
remaining generation customers, and is thus consistent with the Court's 
concerns in AGD about cost shifts due to open access 
transportation.<SUP>605 At the same time, it does not impose any 
crushing new burden on the converting generation customers, as would 
have happened if in the natural gas industry the Commission had 
allocated the take-or-pay settlement costs entirely to pipeline sales 
customers who converted to transportation-only service.
---------------------------------------------------------------------------

    \605\ See, e.g., AGD, 824 F.2d at 1026.
---------------------------------------------------------------------------

    On the issue of utility absorption of stranded costs, as ELCON 
points out, the D.C. Circuit in United Distribution Companies remanded 
Order No. 636 to the Commission for further explanation as to why the 
Commission had exempted pipelines from sharing in Order No. 636 GSR 
costs in light of: (1) Its reliance on ``cost spreading'' and ``value 
of service'' principles in allocating GSR costs among the pipelines' 
customers, and (2) the absorption requirement in Order Nos. 500/528. As 
the Court explained:

    If the Commission intends to assign GSR costs according to these 
`cost spreading' and `value of service' principles, it must do so 
consistently or explain the rationale for proceeding in another 
manner. We approved the invocation of those principles in KN Energy 
because FERC had concluded that the take-or-pay crisis could be 
resolved only by spreading costs throughout the `entire industry' 
968 F.2d at 1301 (emphasis added), and because we recognized that 
`all segments of the industry' * * * will benefit, id. (emphasis 
added), from restructuring.<SUP>[606]

    \606\ United Distribution Companies, 88 F.3d at 1189.
---------------------------------------------------------------------------

    For the reasons discussed above and in Order No. 888, we have 
chosen to use traditional cost causation principles both in allocating 
stranded electric costs to certain electric utility customers and in 
finding that the utilities should be given an opportunity for full 
recovery of certain legitimate, prudent, and verifiable stranded costs. 
Thus, Order No. 888 does not present the issue of whether the 
Commission inconsistently applied ratemaking principles to the recovery 
of stranded costs that was of concern to the court in United 
Distribution Companies when it remanded the analogous portion of Order 
No. 636.
    Moreover, based on the facts summarized above, the Commission 
concludes that the rationale we used to support the Order Nos. 500/528 
absorption requirement is not valid for electric utility costs stranded 
by Order No. 888. Order No. 528-A, where the Commission gave its 
fullest justification for that absorption requirement, did not rely on 
either the ``cost spreading'' or ``value of service'' rationales to 
support the absorption requirement.<SUP>607 Order Nos. 500/528 
consistently recognized that the Commission must ``provide a pipeline a 
reasonable opportunity to

[[Page 12394]]

recover its prudently incurred costs.'' <SUP>608 However, Order No. 
528-A reasoned that, because the take-or-pay problem was caused more by 
general market conditions than by any regulatory action of the 
Commission, it was appropriate to require the pipelines to share in the 
losses arising from those market conditions as a condition to using the 
alternative recovery mechanism.<SUP>609
---------------------------------------------------------------------------

    \607\ Order No. 528-A, 54 FERC para. 61,095 at 61,303-05 (1991).
    \608\ Order No. 500-H, Regulations Preambles 1986-1990, FERC 
Stats. & Regs. at 31,575. Those orders permitted all pipelines to 
seek full recovery of their take-or-pay settlement costs through 
their sales commodity rates. The Commission required pipelines to 
absorb a share of their Order No. 500/528 take-or-pay costs only if 
they chose to use the alternative, equitable sharing recovery 
mechanism.
    \609\ Order No. 528-A, 54 FERC at 61,303-05.
---------------------------------------------------------------------------

    In these circumstances, the Commission concludes that it would not 
be reasonable to require electric utilities to bear costs that, unlike 
the Order Nos. 500/528 take-or-pay costs, arise as the direct result of 
Congress' and the Commission's change in the regulatory regime through 
FPA section 211 and Order No. 888. This is particularly the case since 
the electric utilities' potential stranded costs relate to large 
capital expenditures or long-term contractual commitments (some 
mandated by federal law) to buy power made many years ago in reliance 
on the preexisting regulatory regime.
    Moreover, in a separate order, the Commission is responding to the 
United Distribution Companies remand by reaffirming the policy 
established in Order No. 636 that pipelines should be permitted full 
recovery of their prudently incurred GSR costs. In that order, the 
Commission finds that the rationale Order No. 528-A used to support the 
Order Nos. 500/528 absorption requirement is inapplicable to GSR costs. 
The remand order explains that, in the face of extraordinary market 
conditions, Order Nos. 500/528 adopted extraordinary measures. However, 
as we are finding here with respect to stranded electric utility costs, 
the remand order holds that the extraordinary market circumstances that 
gave rise to the requirement for pipeline absorption of gas supply 
costs in Order Nos. 500/528 were not present at the time of Order No. 
636. Even before the Commission initiated open access transportation in 
Order No. 436, the market was preventing pipelines from recovering 
costs incurred under their take-or-pay contracts. The Order Nos. 500/
528 absorption requirement reflected the preexisting effect of the 
market, which would have required absorption even without open access 
transportation under Order No. 436. The remand order finds that, 
contrary to the situation when Order No. 436 issued, at the time of 
Order No. 636, pipelines were generally able to take gas under their 
few remaining high-priced take-or-pay contracts from the late 1970s and 
early 1980s and were no longer accumulating significant additional 
take-or-pay obligations. This was because the pipelines were still 
performing a significant sales service and had reformed most of their 
uneconomic take-or-pay contracts.<SUP>610
---------------------------------------------------------------------------

    \610\ A number of entities (e.g., VT DPS, Valero, Occidental 
Chemical) challenge the Commission's suggestion that, after Order 
No. 436, many of the former bundled sales customers of the pipeline 
had departed. To the extent that Order No. 888 suggested that many 
pipelines' sales customers had terminated their sales service before 
Order No. 636 issued, we note that, as the Commission indicated in 
Order No. 636, pipeline sales constituted less than 20 percent of 
total annual throughput on major pipelines. FERC Stats. & Regs. 
para.30,939 at 30,400. However, the Commission also found that in 
1991 over 60 percent of peak day capacity on major pipelines that 
made bundled sales was reserved for pipeline firm sales service. Id. 
at 30,399. Thus, we clarify that although on an annual basis 
customers were buying most of their gas from other suppliers, 
pipelines were making significant sales of gas, particularly on peak 
days.
---------------------------------------------------------------------------

    The remand order accordingly holds that the Commission's regulatory 
actions in Order No. 636 have caused the pipelines to incur the GSR 
costs. This is particularly the case because Order No. 636 required the 
pipelines to unbundle their natural gas and transportation sales and 
forbade the pipelines from making sales unless they were made by a 
separate sales or marketing entity. Order No. 888 also requires 
generation or commodity sales to be unbundled from sales of 
transmission. In these circumstances, traditional ratemaking principles 
require the Commission to allow the pipelines an opportunity to recover 
the full amount of the expenses caused by its actions. Thus, the 
Commission's approach to Order No. 636 GSR costs is similar to its 
approach in Order No. 888 to stranded electric generation costs.

Rehearing Requests Citing Other Inconsistencies Between Commission 
Treatments of the Gas and Electric Industries

    VT DPS and Valero submit that Order No. 888 does not satisfactorily 
distinguish the Commission's rejection of gas pipelines' attempts to 
impose exit fees on departing customers. They argue that the Commission 
opposed the imposition of such exit fees in the gas context as 
anticompetitive because it would force customers desiring to switch 
suppliers when their contracts expired to pay the supply costs of both 
the new and former suppliers.
    VT DPS and Valero take issue with the Commission's attempt to 
distinguish a recent El Paso case <SUP>611 as a ``post-restructuring'' 
case under Order No. 636. They contend that the Commission consistently 
applied the same policy (rejection of gas pipeline attempts to impose 
exit fees) before restructuring under Order No. 636. They further claim 
that the Commission cannot articulate a plausible basis for permitting 
utilities with notice provisions to file for exit fees, having denied 
El Paso's proposal outright without giving it an opportunity to rebut 
the presumption.
---------------------------------------------------------------------------

    \611\ El Paso Natural Gas Company, 72 FERC para.61,083 (1995) 
(El Paso).
---------------------------------------------------------------------------

    VT DPS and Valero also state that the ``stranded'' costs for which 
the Commission allowed recovery under Order No. 636 were costs that 
would be rendered unrecoverable because the costs would not be incurred 
to provide transportation service and because there would be no 
wholesale load from which to recover the costs. They indicate that the 
Commission has held that such gas costs are stranded only if rendered 
unrecoverable as a direct result of the restructuring required under 
Order No. 636. They submit that when a utility loses wholesale load or 
a municipality establishes a new distribution system and the utility 
cannot resell the capacity left unused, the utility's costs are not 
necessarily ``stranded''--i.e., rendered unrecoverable--any more than 
if the utility's load declines because of conservation, an economic 
downturn or an increase in self-generation. They argue that the 
Commission should limit utility stranded cost claims solely to those 
cases where the utility can demonstrate that its costs have been 
rendered unrecoverable as a direct result of the Rule.

Commission Conclusion

    We explained in Order No. 888 why we disagree with the argument 
that the Commission cannot impose an exit fee to recover stranded costs 
because the Commission did not allow gas pipelines to do so. We noted 
that the Rule establishes procedures for providing a potential 
departing generation customer advance notice (before it leaves its 
existing supplier) of the stranded cost charge (whether it is to be 
paid as an exit fee or a transmission surcharge) that will be applied 
if the customer decides to buy power elsewhere and the Commission 
decides the utility has satisfied the stranded cost recovery criteria 
of the Rule, e.g., the reasonable expectation criterion. We indicated 
that in the natural gas context, in contrast, the Commission has 
prohibited

[[Page 12395]]

pipelines from developing and charging an ``exit fee'' after a customer 
had implemented its gas purchase decision, noting that otherwise, the 
customer would not know in advance the full cost consequences of its 
nomination decision.<SUP>612
---------------------------------------------------------------------------

    \612\ FERC Stats. & Regs. at 31,802; mimeo at 489.
---------------------------------------------------------------------------

    We continue to believe that the Commission's decisions concerning 
natural gas pipeline exit fees, relied on by VT DPS and Valero, are not 
inconsistent with Order No. 888's limited approval of exit fees for the 
recovery of certain stranded electric utility costs. VT DPS and Valero 
point first to two cases decided by the Commission in 1988 and 1989 
involving Gas Inventory Charges (GICs) proposed by Transwestern 
Pipeline Company (Transwestern) <SUP>613 and El Paso Natural Gas 
Company (El Paso) <SUP>614 pursuant to our Order No. 500 policy 
statement. However, those cases are not relevant here, essentially 
because the exit fees at issue in those cases were not designed to 
recover costs arising from the transition to open access 
transportation, unlike the stranded electric utility costs at issue 
here.
---------------------------------------------------------------------------

    \613\ Transwestern Pipeline Company, 44 FERC para. 61,164 at 
61,536 (1988) (Transwestern).
    \614\ El Paso Natural Gas Company, 47 FERC para. 61,108 at 
61,314, reh'g denied, 48 FERC para. 61,202 (1989).
---------------------------------------------------------------------------

    In the Transwestern case cited by VT DPS and Valero, Transwestern 
included in its proposal to implement a GIC a request for permission to 
assess an exit fee. The exit fee would have been charged to its largest 
local distribution company customer if that customer initially chose to 
nominate purchases under the GIC but then subsequently reduced its 
nominations. The Commission found the proposed exit fee inconsistent 
with both (1) its policy that GIC customers know in advance the full 
cost consequences of their nomination decisions and (2) its objective 
that prices under the GIC be constrained by market forces.
    However, this holding was not applicable to Transwestern's recovery 
of costs incurred as part of its transition to open access 
transportation, since the Commission did not intend the GIC as a 
vehicle for recovery of such transition costs. The GIC was intended 
solely as a forward-looking charge that would recover costs the 
pipeline would incur in the future under its reformed, market 
responsive gas supply contracts.<SUP>615 The Commission's intent was 
that, before implementing GICs, pipelines would negotiate settlements 
of their existing uneconomic take-or-pay contracts and file to recover 
the resulting settlement costs under the Order No. 500 equitable 
sharing mechanism.<SUP>616 Indeed, in the Transwestern order cited by 
VT DPS and Valero, the Commission suggested that Transwestern postpone 
implementation of its GIC until it had renegotiated its supply 
contracts and filed to recover the resulting costs under the Order No. 
500 equitable sharing mechanism.<SUP>617
---------------------------------------------------------------------------

    \615\ Order No. 500, Regulations Preambles (1986-1990), FERC 
Stats. & Regs. para.30,761 at 30,793-94 (1987).
    \616\ CPUC v. FERC, 988 F.2d 154, 168 (D.C. Cir. 1993), quoting, 
Transwestern Pipeline Company, 55 FERC para.61,157 at 61,509 (1991).
    \617\ Transwestern, 44 FERC at 61,536. The 1989 El Paso order 
cited by VT DPS and Valero (47 FERC para.61,108) reiterated the 
policy established in Transwestern concerning exit fees in the 
context of GICs. The El Paso order is distinguishable from our 
approach to exit fees in Order No. 888 for the same reasons as 
Transwestern.
---------------------------------------------------------------------------

    That mechanism included a fixed take-or-pay charge analogous to the 
direct assignment provisions of Order No. 888. The Commission permitted 
pipelines to allocate to sales customers who converted from sales to 
transportation the same fixed take-or-pay charge that those customers 
would have been allocated had they not converted.<SUP>618 Moreover, in 
a later order involving Transwestern's recovery of take-or-pay 
settlement costs under its Order No. 500 equitable sharing mechanism, 
the Commission expressly held:

    \618\ Natural Gas Pipe Line Company, 46 FERC para. 61,335 at 
62,013 (``Consistent with the court's holding in AGD, that Part 284 
transportation and CD conversion must be accompanied by take-or-pay 
relief, the Commission finds that a pipeline's sales customers who 
convert to transportation must continue to be liable for the take-
or-pay costs allocated to them without regard to the fact that they 
are no longer sales customers but only transportation customers.''), 
reh'g denied, 47 FERC para.61,247 (1989); Transwestern Pipeline 
Company, 65 FERC para.61,060 at 61,473 (1993), reh'g denied, 66 FERC 
para.61,287 at 61,827-828 (1994), aff'd sub nom. Western Resources, 
Inc. v. FERC, 72 F.3d 147 (D.C. Cir. 1996).
---------------------------------------------------------------------------

    In appropriate circumstances, the Commission may approve exit 
fees for departing customers, either through a condition on the 
abandonment of the purchase obligation of customers subject to the 
Commission's jurisdiction or through tariff language giving 
appropriate notice of such a fee before the departure.<SUP>[619]]

    \619\ Transwestern Pipeline Company, 64 FERC para.61,145 at 
62,166 (1993), reh'g denied, 66 FERC para.61,287 (1994). However, as 
illustrated by the situation described in the cited Transwestern 
order, some sales customers had departed altogether from the systems 
of their historical pipeline suppliers before the Commission 
recognized the need for continued allocation of Order No. 500 take-
or-pay costs to those customers. In these circumstances, the filed 
rate doctrine prevented such continued allocation.
---------------------------------------------------------------------------

    As discussed in the preceding section of this order, the direct 
assignment provisions of Order No. 888, in essence, require that 
certain electric generation customers who convert to transmission-only 
service continue, for a period, to bear certain generation costs that 
they were previously bearing. That requirement is similar to the 
Commission's requirement, in connection with its Order No. 500 program, 
that pipeline sales customers who convert to transportation-only 
service continue to pay the same Order No. 500 fixed take-or-pay charge 
as they would have paid had they not converted.
    VT DPS and Valero also claim that permitting electric utilities to 
recover stranded generation costs through exit fees to customers 
converting to transmission-only service is inconsistent with our 1995 
order in El Paso,<SUP>620 rejecting that pipeline's exit fee proposal. 
We see no inconsistency. El Paso proposed, several years after its 
restructuring pursuant to Order No. 636, to impose an exit fee on its 
firm transportation customers who terminated or reduced their firm 
transportation service. The fee was designed to require the departing 
firm transportation customer to continue to pay a portion of El Paso's 
fixed transmission costs for a period of time after the customer's 
departure. The fee bore no relationship to El Paso's pre-restructuring 
merchant function, since it was designed to recover El Paso's costs of 
performing open access transportation service after its restructuring.
---------------------------------------------------------------------------

    \620\ 72 FERC para.61,083 (1995).
---------------------------------------------------------------------------

    In both Order No. 888 and this order, we are acting consistently 
with El Paso. Similar to our refusal in El Paso to permit a pipeline to 
impose an exit fee on customers departing its transportation system 
altogether (whether for all or a portion of their firm service), so 
also here we are refusing to permit electric utilities to recover 
stranded costs from customers who depart their transmission systems 
altogether. We believe that, in that situation, there is no direct 
nexus between the customer's departure (and the stranding of costs) and 
Commission-required transmission access, since the customer is not 
using its former supplier's open access tariff to reach an alternative 
power supplier.
    Order No. 888 thus permits an exit fee only to electric generation 
customers who, although they stop purchasing power from the utility, 
become transmission-only customers of the former supplying 
utility.<SUP>621 By contrast,

[[Page 12396]]

El Paso proposed an exit fee to transmission customers terminating 
their transmission service. In short, the exit fee we have found 
acceptable in Order No. 888 is related to the electric utility's pre-
restructuring generation service, unlike El Paso's rejected exit fee, 
which bore no relationship to El Paso's pre-restructuring merchant 
service.<SUP>622
---------------------------------------------------------------------------

    \621\ In Order Nos. 636-A and 636-B, the Commission not only 
rejected exit fees where the customer left the system altogether, 
but also found exit fees unnecessary for the recovery of GSR costs 
in the circumstance in which a bundled sales customer converts to 
transportation-only service. See Order No. 636-B, 61 FERC para. 
61,272 at 62,041 (1992). Exit fees were unnecessary in the latter 
circumstance because under the Commission's method of allocating GSR 
costs to all firm transportation customers based on their contract 
demands, a former bundled sales customer would pay the same GSR 
costs after terminating its sales service (through the volumetric 
surcharge on transportation) as it would if it had remained as a 
sales customer.
    \622\ As we explained in Order No. 888, the Commission did not 
treat a notice of termination provision in El Paso's contract as a 
conclusive presumption that El Paso had no reasonable expectation of 
continuing to serve certain customers, as VT DPS and Valero contend. 
FERC Stats. & Regs. at 31,802, note 639; mimeo at 489, note 639. 
Instead, the July 1995 El Paso order acknowledged that the April 
1995 Supplemental Stranded Cost NOPR had proposed that the existence 
of a notice of termination provision in a contract be treated as a 
``rebuttable'' presumption of no reasonable expectation. On that 
basis, the Commission suggested in dicta that ``[e]ven if the rules 
proposed in [the Supplemental Stranded Cost] NOPR were applied here 
[which they were not], El Paso would have difficulty justifying'' 
its exit fee proposal under the NOPR's reasonable expectation 
standard given the existence of a notice of termination provision in 
the contract. 72 FERC at 61,441 (emphasis added).
---------------------------------------------------------------------------

    Finally, VT DPS's and Valero's comments concerning the Commission's 
treatment of Order No. 636 ``stranded costs'' attempt to make 
distinctions that do not make a difference for purposes of the 
Commission's treatment of Order No. 888 stranded costs. We have 
explained above that the electric industry's transition to an open 
transmission access, competitive industry is different in a number of 
respects from the natural gas industry's transition to open access 
transportation service by interstate natural gas pipelines. We also 
have explained why a different approach to recovery of legitimate, 
prudent and verifiable stranded costs in the electric industry is 
justified. On this basis, the Commission's definition and treatment of 
``stranded'' costs under Order No. 636 need not dictate our definition 
and treatment of stranded costs under Order No. 888. In any event, in 
response to VT DPS's and Valero's request that the Commission limit 
utility stranded cost claims solely to those cases where the utility 
can demonstrate that its costs have been rendered unrecoverable as a 
direct result of the Rule,<SUP>623 we note that Order No. 888 does 
require a causal nexus between the availability and use of Commission-
required transmission access and the stranding of costs.
---------------------------------------------------------------------------

    \623\ Under their proposal, it appears that costs would be 
``unrecoverable'' only if there were no wholesale load from which to 
recover the costs. This would result in shifting costs to customers 
that had no responsibility for causing them to be incurred or for 
causing them to be stranded. In Order No. 888, we rejected such an 
approach as fundamentally unfair and as inconsistent with the well-
established principle of cost causation.
---------------------------------------------------------------------------

Rehearing Requests Opposing Recovery of Stranded Costs in Transmission 
Rates

    VT DPS and Valero submit that although the Commission has not 
proposed to depart from cost-based ratemaking methodologies in 
establishing transmission rates, Order No. 888 contravenes cost 
causation principles by recovering generating costs in transmission 
rates.<SUP>624 They argue that although the court in KN Energy held 
that the Commission might depart from strict cost-causation principles 
to permit pipelines to recover gas supply costs from transportation 
customers in extraordinary circumstances, the ``extraordinary 
circumstances'' were that the pipelines had no remaining sales 
customers and thus were left with no vehicle for recovering gas supply 
costs. On this basis, the court approved a mechanism under which gas 
supply costs were spread over virtually all transmission users. They 
describe as incongruous the Commission's claim in Order No. 888 that 
permitting direct assignment of stranded power costs in a transmission 
rate is a cost-based approach.
---------------------------------------------------------------------------

    \624\ In support of this argument, they cite CPUC v. FERC, 894 
F.2d 1372, 1380-81 (D.C. Cir. 1990) as standing for the proposition 
that, in a cost-based transmission rate, there is no logical basis 
for including gas-supply related expenses or savings in the rates 
for customers who take only transmission service. See also American 
Forest & Paper (no justification for including excess generation 
costs in transmission rates).
---------------------------------------------------------------------------

    VT DPS and Valero further argue that even if the Commission were 
inclined to justify stranded cost recovery from departing customers on 
non-cost grounds, the Commission cannot show that the circumstances 
justifying similar cost recovery from gas pipeline transportation 
customers exist at the wholesale level in the electric industry 
because: (1) unlike its approach to gas pipelines, the Commission has 
not proposed to allow existing wholesale electric customers to get out 
of their contracts early; (2) there is no industry-wide problem; 
wholesale sales account for only a small fraction of the total business 
of regulated electric utilities, while gas pipelines had virtually all 
wholesale sales; and (3) direct assignment of generating costs only to 
departing customers is the antithesis of the cost-spreading rationale 
that provided the justification for the limited departure from cost-
causation principles permitted in KN Energy. They contend that, in any 
event, the Commission cannot spread costs broadly even if they are 
recovered from all transmission customers because the largest users are 
retail customers that would be exempt from wholesale stranded cost 
surcharges.
    A number of other entities also oppose the recovery of stranded 
generation costs in transmission rates.<SUP>625 Some of them contend 
that section 212(a) of the FPA limits the transmitting utility to the 
recovery of transmission-related costs.<SUP>626 PA Munis contends that 
the plain language of section 212, as amended by EPAct, limits the 
rates that can be charged under a section 211 order to those `` `which 
permit the recovery by such utility of all the costs incurred in 
connection with the transmission services and necessary associated 
services * * * '''<SUP>627 PA Munis contends that Congress would not 
have limited recovery to the costs incurred in connection with the 
transmission services and necessary associated services if it had 
intended to allow the transmission rates to include part of a utility's 
costs for unused generation facilities completely unrelated to the cost 
of the transmission facilities.<SUP>628 PA Munis asserts that the 
legislative history of EPAct supports its position that there is no 
authorization for the Commission to include unused generation costs as 
part of the transmission costs that are allocable to transmission under 
section 212.<SUP>629
---------------------------------------------------------------------------

    \625\ E.g., TX Com, APPA, IN Consumer Counselor, IN Consumers, 
PA Munis, AR Com, MO/KS Coms.
    \626\ E.g., APPA, PA Munis, IN Consumer Counselor, IN Consumers.
    \627\ PA Munis at 28. PA Munis also argues that the last 
sentence of section 212(a) makes it clear that the ``rates, charges 
* * * for transmission services provided pursuant to an order under 
section 211 shall ensure that to the extent practicable, costs 
incurred in providing the wholesale transmission services, and 
properly allocable to the provision of such services are recovered * 
* *. ' '' (emphasis added by PA Munis).
    \628\ See also IN Consumers, IN Consumer Counselor.
    \629\ PA Munis cites in support the following excerpt from House 
Report No. 102-474, Part I: This section [211] also provides that 
FERC shall permit the transmitting utility to recover all prudent 
costs incurred in connection with providing transmission services, 
plus a reasonable return on investment, including an appropriate 
share of the costs of any enlargement of transmission facilities 
necessary to provide such service. H.R. Rep. No. 102-474, Part I, 
102d Cong., 2d Sess. 194 (1992), reprinted in 1992 U.S.C.C.A.N. 
1959, 2017 (emphasis supplied by PA Munis).

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

[[Page 12397]]

    AR Com and MO/KS Coms argue that the FPA does not allow the 
Commission to include costs in a transmission rate that are not caused 
by the provision of transmission service.<SUP>630 MO/KS Coms contend 
that retail stranded costs are largely generation costs that were not 
caused by any request to use transmission service or by any actual 
transmission usage, and are not an opportunity cost of providing 
transmission service. Citing the language in section 212 of the FPA 
allowing the transmitting utility to recover ``all costs incurred in 
connection with the transmission services and necessary associated 
services,'' AR Com contends that nowhere does the Energy Policy Act or 
any other relevant statute authorize the collection of retail, non-
transmission costs through transmission rates.
---------------------------------------------------------------------------

    \630\ They cite in support of this proposition Farmers Union 
Central Exchange, Inc. v. FERC, 734 F.2d 1486 (D.C. Cir.), cert. 
denied, Williams Pipe Line Company v. Farmers Union Central 
Exchange, Inc., 469 U.S. 1034 (1984).
---------------------------------------------------------------------------

Commission Conclusion

    We disagree with VT DPS's and Valero's argument that Order No. 888 
contravenes cost causation principles by recovering generating costs in 
transmission rates. As the court in United Distribution Companies 
stated: `` `Cost causation' correlates costs with those customers for 
whom a service is rendered or a cost is incurred.'' <SUP>631 Whether 
stranded costs are recovered through a surcharge on the transmission 
rates of a departing generation customer, or through an exit fee, the 
point is that under Order No. 888 they are recovered from the customer 
that caused them to be incurred. The only distinction is the mechanism 
by which they are recovered from that customer.
---------------------------------------------------------------------------

    \631\ 88 F.3d at 1188-89.
---------------------------------------------------------------------------

    The Commission is not aware of any prohibition on permitting 
recovery through a transmission rate of what has traditionally been 
recovered through the generation component of a rate, so long as the 
utility does not double recover and the customer does not pay more than 
the costs that it caused to be incurred.<SUP>632 Indeed, the Commission 
has been upheld in permitting opportunity costs (foregone economic 
savings) to be charged as a transmission rate when they are higher than 
a traditional embedded cost transmission rate.<SUP>633 There is no 
significant difference between an ``opportunity cost'' component of a 
transmission rate and a stranded cost charge imposed through 
transmission rates. Both concern the recovery of generation costs. To 
be sure, in the former case these generation costs are incurred by 
reason of using high cost generation instead of substituting lower cost 
generation, and in the latter case the costs are ``incurred'' by reason 
of the loss of a customer.<SUP>634 But, for purposes of cost recovery, 
these are distinctions without a difference. In both situations, the 
transmission rate is used to recover something other than the capital, 
operating, and maintenance costs of facilities used to provide the 
transmission service at issue. If the Commission were without authority 
to provide for cost recovery of these other types of costs in 
transmission rates, the court would not have affirmed the volumetric 
surcharge on transportation in KN Energy, nor would it have affirmed 
the opportunity cost charge in Penelec.
---------------------------------------------------------------------------

    \632\ Additionally, we note that a stranded cost surcharge to 
transmission is merely a vehicle for collecting the exit fee. The 
surcharge would be in effect only until the stranded cost obligation 
is met. It is not a component of the transmission rate in the sense 
that a transmission customer who uses a very large amount of 
transmission while the rate is in effect would pay more than its 
stranded cost obligation.
    \633\ See Pennsylvania Electric Company v. FERC, 11 F.3d 207 
(D.C. Cir. 1993) (Penelec). As the Commission explained, opportunity 
costs are the actual costs that a utility incurs by providing 
transmission service to a customer instead of using the transmission 
itself to reduce its generation costs on behalf of its native load 
(i.e., the foregone economy energy transfers). Pennsylvania Electric 
Company, 60 FERC para.61,034 at 61,120, 61,126 (1992), aff'd, 
Penelec, 11 F.3d 207.
    \634\ Technically, the costs in the latter situation were 
previously incurred as a result of investment by the utility on 
behalf of the departing customer. However, the costs are 
``incurred'' in the sense of becoming stranded when the customer 
leaves the utility's system. In both situations, recovery of the 
costs is permitted through transmission rates in order to keep the 
utility (and its other customers) from unfairly suffering economic 
losses as a result of providing transmission to others.
---------------------------------------------------------------------------

    As we note above, we are not proposing a departure from strict 
cost-causation principles such as that allowed in KN Energy, where the 
pipeline was allowed to recover 50 percent of its take-or-pay 
settlement costs through a volumetric surcharge on all transportation 
customers, including those that had never purchased gas from the 
pipeline.<SUP>635 Because we disagree with VT DPS's and Valero's 
position that recovery of stranded costs through a surcharge on 
transmission constitutes recovery on non-cost grounds,<SUP>636 we will 
reject their requests for rehearing on this issue.<SUP>637
---------------------------------------------------------------------------

    \635\ Moreover, we note that, in addressing the natural gas 
industry's transition costs, the Commission did rely on traditional 
cost causation principles in approving pipeline proposals to 
allocate fixed take-or-pay charges to sales customers converting to 
transportation-only service. See Transwestern Pipeline Company, 65 
FERC para.61,060 at 61,473 (1993), reh'g denied, 66 FERC para.61,287 
at 61,825-28 (1994). The Commission found that the pipelines entered 
into their take-or-pay contracts to serve their sales customers. The 
conversion of those customers to open access transportation required 
pipelines to enter into settlements with producers to shed gas 
supplies. Therefore, there was a causal connection between the 
customer's conversion and the pipeline's incurrence of the take-or-
pay settlement costs. Here, there is a similar causal connection 
between the stranding of generation investment made on behalf of a 
wholesale customer and that customer's decision to use Commission-
mandated open access transmission to reach a new supplier.
    \636\ The case on which VT DPS and Valero rely, CPUC v. FERC, 
involved the disposition of a pipeline's production-related deferred 
tax reserve when the switch to NGPA pricing mooted application of 
tax normalization (which sought to match the timing of a customer's 
contribution toward a cost with enjoyment of any offsetting tax 
benefit). The Commission's decision not to credit the deferred tax 
reserve to current users of the pipeline's transmission service was 
based, among other things, on a determination that the deferred tax 
fund was completely unrelated to the pipeline's transmission 
service. See 894 F.2d at 1378-80. In contrast, as discussed below, 
the costs for which this Rule provides an opportunity for recovery 
would not have been stranded but for Commission-mandated 
transmission access.
    \637\ We also reject AR Com's argument that the Farmers Union 
case prohibits the Commission from allowing the recovery of non-
transmission costs in a transmission rate in the limited 
circumstances proposed in Order No. 888. The issues before the court 
in that case are distinguishable from the recovery of stranded 
generation costs in transmission rates. Farmer's Union involved the 
court's review of a Commission order establishing maximum rate 
ceilings to be applied to oil pipelines in which the Commission 
invoked non-cost factors (the need to stimulate additional oil 
pipeline capacity) as one reason for setting high maximum rates. The 
use of non-cost factors was itself not at issue. Rather, the court 
found that the Commission had ``failed to specify in any detail how 
`non-cost' factors, such as the need to stimulate additional 
pipeline capacity, might justify its decision to set maximum rates 
at such high levels.'' 734 F.2d at 1501. In Order No. 888, in 
contrast, the Commission has fully explained the basis for giving 
utilities an opportunity to recover stranded costs from departing 
customers through a surcharge to the customers' transmission rates.
---------------------------------------------------------------------------

    We also reject the argument that section 212 of the FPA prohibits 
the recovery of stranded generation costs in transmission rates. There 
is nothing on the face of the statute or in its legislative history to 
support this position. In fact, section 212(a) permits recovery of 
``legitimate, verifiable and economic costs'' of providing transmission 
service. Stranded costs clearly are an economic cost of providing 
transmission when the stranding results from the ordered transmission 
service. By definition, the costs for which this Rule provides an 
opportunity for recovery would not have been stranded but for 
Commission-mandated transmission access. Stranded costs under this Rule 
are the costs that a utility incurred to provide service to a customer 
based on a reasonable expectation that the utility would continue to 
serve the customer beyond the term of their contract, and that become 
stranded when the customer uses Commission-mandated

[[Page 12398]]

transmission access to reach a new generation supplier. In this 
respect, stranded costs, like opportunity costs,<SUP>638 are not costs 
associated with the actual facilities used to provide transmission 
service. Rather, they are an ``economic cost'' of providing the 
transmission service at issue.
---------------------------------------------------------------------------

    \638\ See note 633 supra.
---------------------------------------------------------------------------

4. Recovery of Stranded Costs Associated With New Wholesale 
Requirements Contracts
    In Order No. 888, we concluded that future wholesale requirements 
contracts should explicitly address the mutual obligations of the 
seller and buyer, including the seller's obligation to continue to 
serve the buyer, if any, and the buyer's obligation, if any, if it 
changes suppliers. This means that utilities must address potential 
stranded cost issues when negotiating new contracts or be held strictly 
accountable for the failure to do so.
    We stated that we will allow recovery of wholesale stranded costs 
associated with any new requirements contract (executed after July 11, 
1994, or extended or renegotiated to be effective after July 11, 1994) 
only if explicit stranded cost provisions are contained in the 
contract. We defined ``explicit stranded cost provision'' (for 
contracts executed after July 11, 1994) as a provision that identifies 
the specific amount of stranded cost liability of the customer(s) and a 
specific method for calculating the stranded cost charge or rate. 
However, for purposes of requirements contracts executed after July 11, 
1994 but before May 10, 1996 (the date on which Order No. 888 was 
published in the Federal Register), we clarified that a provision that 
specifically reserved the right to seek stranded cost recovery 
consistent with what the Commission permits in the Final Rule (without 
identifying the specific amount of stranded cost liability of the 
customer(s) and calculation method) nevertheless will be deemed an 
``explicit stranded cost provision.'' On the other hand, a provision in 
a requirements contract executed after July 11, 1994 but before May 10, 
1996 that merely postpones the issue of stranded cost recovery without 
specifically providing for such recovery will not be considered an 
``explicit stranded cost provision.'' We said that, after May 10, 1996, 
a provision must identify the specific amount of stranded cost 
liability of the customer(s) and a specific method for calculating the 
stranded cost charge or rate in order to constitute an ``explicit 
stranded cost provision.'' <SUP>639
---------------------------------------------------------------------------

    \639\ See Orange and Rockland Utilities, Inc., 76 FERC para. 
61,037 (1996).
---------------------------------------------------------------------------

    We also concluded that a requirements contract that is extended or 
renegotiated for an effective date after July 11, 1994 becomes a 
``new'' requirements contract for which stranded cost recovery will be 
allowed only if explicitly provided for in the contract.
    We decided not to impose a regulatory obligation on wholesale 
requirements suppliers to continue to serve the power needs of their 
existing requirements customers beyond the end of the contract term. 
The only exception to this would be if the customer decides to remain a 
requirements customer for the period for which the Commission finds 
that the supplying utility reasonably expected to continue serving the 
customer. In such a case, the supplying utility will be obligated to 
offer continuing service to the requirements customer for the period 
the utility reasonably expected to continue serving the customer.
    We also decided to no longer require prior notice of termination 
under section 35.15 for any power sales contract executed on or after 
July 9, 1996 (the effective date of the Final Rule pro forma tariff) 
that is to terminate by its own terms (such as on the contract's 
expiration date), but to require written notification of the 
termination of such contract within 30 days after termination takes 
place. We said that we will continue to require prior notice of the 
proposed termination of any power sales contract executed before July 
9, 1996 (even if the contract is to terminate by its own terms) as well 
as any unexecuted power sales contract that was filed before that date.
    Further, we decided to retain the section 35.15 filing requirement 
for all transmission contracts because the Commission must be assured 
that transmission owners are not exerting market power in negotiating 
or terminating transmission contracts. This filing requirement will 
provide the customer an opportunity to notify the Commission if the 
termination terms are disputed or if the customer was not given 
adequate opportunity to exercise its limited right of first refusal 
under the Final Rule (see Section IV.A.5).<SUP>640
---------------------------------------------------------------------------

    \640\ FERC Stats. & Regs. at 31,804-06; mimeo at 497-501.
---------------------------------------------------------------------------

Requests for Rehearing

    Utilities For Improved Transition asks the Commission either to 
clarify that it will enforce stranded cost provisions as agreed to by 
the parties and accepted for filing by the Commission (presumably even 
if they do not meet the definition of ``explicit stranded cost 
provision'' contained in the Preamble <SUP>641), or to modify the 
definition contained in the Preamble (and add the term to the list of 
definitions in section 35.26(b)) to give contracting parties the option 
of specifying either a specific amount of stranded cost liability or a 
formula for calculating the stranded cost charge or rate. Utilities For 
Improved Transition contends that, particularly in the case of long-
term contracts, the parties may not be able to quantify what the 
stranded cost liability will be at the time they enter into a contract.
---------------------------------------------------------------------------

    \641\ FERC Stats. & Regs. at 31,805; mimeo at 497.
---------------------------------------------------------------------------

    Several entities assert that if the Commission is to permit 
recovery for stranded costs, it should include a symmetrical mechanism 
to permit customers with below-market rates or net undervalued assets a 
means to continue to receive power at below-market rates if the 
customer had a reasonable expectation of continued service.<SUP>642 OH 
Consumers' Counsel objects that the only exception in Order No. 888 to 
the Commission's decision not to impose a regulatory obligation on a 
utility to continue to serve existing requirements customers beyond the 
end of the contract ``would be if the customer decides to remain a 
requirements customer for the period for which the Commission finds 
that the supplying utility reasonably expected to continue serving the 
customer.'' <SUP>643 According to OH Consumers' Counsel, this language 
nullifies the customer's reasonable expectation of continuation of 
service under its existing contractual arrangement.
---------------------------------------------------------------------------

    \642\ E.g., TDU Systems, OH Consumers' Counsel. TDU Systems 
proposes that the Commission give a requirements customer the choice 
of extending its existing contract at existing rates for a period 
corresponding to the customer's expectation of continued service or 
receiving a payment from the utility consisting of the difference 
between what the customer must pay for new supplies and what it paid 
under the contract. TDU Systems describes the latter option as a 
``benefits lost'' approach modeled after the ``revenues lost'' 
approach of Order No. 888.
    \643\ FERC Stats. & Regs. at 31,805; mimeo at 498 (emphasis 
added by OH Consumers' Counsel).
---------------------------------------------------------------------------

    TDU Systems similarly says that the Commission has not explained 
why the suppliers' expectations are to be honored, but the customers' 
expectations are not. TDU Systems objects that the Commission failed to 
explain why it rejected allowing requirements customers to demonstrate 
a reasonable expectation that they would continue to be able to obtain 
supplies of power at rates based on embedded cost after the expiration 
of

[[Page 12399]]

their supply contracts. TDU Systems submits that the case for providing 
extra-contractual relief to wholesale purchasers is more compelling 
than the case for providing extra-contractual relief to wholesale 
suppliers. It argues that it is likely that some cooperatives and 
municipal utilities would not survive the drastic impact to their 
businesses that the elimination of cost-based rates could bring.
    OH Consumers' Counsel submits that the filing of a section 206 
complaint by customers of utilities with rates below market does not 
provide adequate protection or symmetry for the customers. It contends 
that a section 206 case is an inadequate remedy because: (1) the 
utility holds all of the necessary information for analyzing such a 
case, but the procedure shifts the burden of proof from the utility to 
the customer; and (2) it provides only delayed relief for parties who 
could be irreparably harmed by the imposition of the market-based 
rates.
    TDU Systems argues that eliminating the prior notice of termination 
requirement in section 35.15 for post-July 9, 1996 wholesale 
requirements contracts will result in discrimination and 
monopolization. It contends that the Commission closes its eyes to the 
fact that termination of a requirements contract can affect 100 percent 
of a customer's power supply, while it is likely to affect less than 10 
percent of a large public utility's load. It submits that eliminating 
the prior notice of termination requirement is tantamount to finding 
that termination of all such contracts by their terms will be just and 
reasonable, but that no such finding can presently be supported. TDU 
Systems maintains that there remains significant market power in the 
markets in which transmission dependent utilities, especially small 
transmission dependent utilities, operate. It recommends that the 
Commission use section 35.15 to require that wholesale contracts not be 
terminated unless such termination is just and reasonable.
    PA Munis objects that the Commission did not specifically address 
in Order No. 888 its proposal that contracts approved after July 11, 
1994 (but executed before that date) be treated as new contracts. It 
submits that under the Commission's reasoning in setting the July 11, 
1994 cut-off date, utilities that executed requirements contracts after 
that date had no reasonable expectation that they would be permitted to 
recover costs by seeking to amend the contract. It argues that the same 
reasoning applies where the contract was executed but not approved or 
accepted by the Commission by the July 11, 1994 notice date.

Commission Conclusion

    We will clarify the definition of ``explicit stranded cost 
provision'' for requirements contracts executed after July 11, 1994. As 
long as the contracting parties are in agreement, a provision in a 
post-July 11, 1994 requirements contract will be considered an 
``explicit stranded cost provision'' if it identifies either the 
specific amount of stranded cost liability of the customer or a 
specific method for calculating the stranded cost charge or rate.
    We will reject the arguments of TDU Systems and OH Consumers' 
Counsel that ``symmetry'' requires that the Commission provide a 
generic mechanism in this Rule to allow existing requirements customers 
with below-market rates a means to continue to receive power beyond the 
contract term at the pre-existing contract rate if the customer had a 
reasonable expectation of continued service. Unlike the generic 
findings we have made with respect to extra-contractual recovery of 
stranded costs associated with requirements contracts executed on or 
before July 11, 1994, we do not have a sufficient basis on which to 
make generic findings that customers under such contracts may be 
entitled to extend a contract at the existing rate. Utilities' 
expectations may have resulted in millions of dollars of investments on 
behalf of certain customers and the possibility of shifting the costs 
of those investments to other customers that did not cause the costs to 
be incurred. In the case of customers' expectations, however, even if 
customers generally expected to stay on a supplier's system beyond the 
contract term, it is not likely that most customers could have expected 
to continue service at the existing rate unless specified in the 
contract. Moreover, the consequences of customers' expectations as a 
general matter would not have the potential to shift significant costs 
to other customers.
    Nevertheless, our conclusion that we cannot make generic findings 
or provide a generic formula for addressing this issue does not mean 
that a customer under a contract may not exercise its procedural rights 
under section 206 to show that the contract should be extended at the 
existing contract rate,<SUP>644 or to make such a showing in the 
context of a utility's proposed termination of a contract pursuant to 
the section 35.15 notice of termination (approval) requirement, which 
we have retained for power supply contracts executed prior to July 9, 
1996 (the effective date of the Rule).
---------------------------------------------------------------------------

    \644\ If the customer under a contract has not waived its rights 
to seek changes to the contract, it may exercise its procedural 
rights under section 206 to show that failure to extend the contract 
at the existing contract rate would not be just and reasonable. If 
the customer has waived its rights to challenge the contract (i.e., 
it is bound by a Mobile-Sierra standard), it may exercise its rights 
under section 206 to show that it would be contrary to the public 
interest not to extend the contract at the existing rate. Although 
OH Consumers' Counsel objects that a section 206 proceeding is an 
inadequate remedy because it places the burden of proof on the 
customer, we believe that it is appropriate that the customer, as 
the complainant in such a case, bear the burden of proof.
---------------------------------------------------------------------------

    We believe that while the relationship between utilities and their 
wholesale requirements customers may have given rise to an inference or 
expectation on the part of the wholesale requirements customer that the 
contract would continue beyond the stated term, it is not clear to what 
extent a customer could demonstrate a reasonable expectation that such 
continued service would be at the existing contract rate (which may be 
below the market price). This is particularly the case for contracts in 
which the utility has not waived its unilateral right to make section 
205 filings to change the rates. Even in contracts where rates were 
fixed for the contract term, however, if the utility were to agree to 
extend such a contract for a new term, the rates under that contract 
would not necessarily have remained the same. On this basis, a customer 
may be able to demonstrate that it had a reasonable expectation of 
continued service beyond the contract term, but not necessarily at the 
same rate level. It is for this reason that we believe this issue must 
be addressed on a case-by-case basis and that this Rule is not the 
proper mechanism for granting the relief sought by TDU Systems and OH 
Consumers Counsel.
    Nevertheless, we do not intend to prejudge whether a requirements 
customer could ever make a showing that it reasonably expected service 
beyond the contract term at the existing contract price. Nor do we 
intend to preclude a customer from attempting to make such a showing in 
appropriate circumstances.
    We also believe that we adequately addressed in Order No. 888 TDU 
Systems' argument that elimination of the prior notice of termination 
requirement in section 35.15 for post-July 9, 1996, wholesale 
requirements contracts will result in discrimination and 
monopolization. As we stated in Order No. 888, we believe that the 
concerns of TDU Systems can be fully addressed without retaining the 
section

[[Page 12400]]

35.15 prior notice of termination requirement for post-July 9, 1996 
contracts. While we have agreed to provide for extra-contractual 
stranded cost recovery as a transition matter, it is our objective 
that, prospectively, parties should address their mutual expectations 
clearly through contract terms that explicitly address the mutual 
obligations of the seller and buyer at contract expiration. This would 
include the seller's obligation to continue to serve the buyer after 
contract expiration, if any. If the customer believes that termination 
of its contract at the end of the term would not be just and reasonable 
(or, in the case of a Mobile-Sierra contract, would not be in the 
public interest), it can file a complaint with the Commission under 
section 206 of the FPA.
    We will reject PA Munis' request that contracts approved after July 
11, 1994 (but executed before that date) be treated as ``new'' 
contracts for purposes of stranded cost recovery because modifying the 
notice date at this point in the proceeding would work an inequitable 
result. Beginning with the initial stranded cost NOPR, the Commission 
put entities on notice that contracts ``executed'' on or before July 
11, 1994 would constitute ``existing'' contracts. Although a utility 
arguably could have amended such an existing contract to include an 
explicit stranded cost provision prior to its (post-July 11, 1994) 
approval by the Commission, the NOPR did not require the utility to do 
so. As a result, it would be unfair for the Commission to change the 
cut-off terms now.
5. Recovery of Stranded Costs Associated With Existing Wholesale 
Requirements Contracts
    In Order No. 888,<SUP>645 the Commission concluded that it would 
permit utilities the opportunity to seek recovery of legitimate, 
prudent and verifiable stranded costs for ``existing'' wholesale 
requirements contracts (executed on or before July 11, 1994) that do 
not already contain exit fees or other explicit stranded cost 
provisions.<SUP>646 We explained why we believe that July 11, 1994--the 
date on which the initial Stranded Cost NOPR was published and, thus, 
on which the industry was put on notice of the proposal to disallow 
prospectively extra-contractual recovery of stranded costs--is the 
appropriate date for distinguishing ``existing'' requirements contracts 
from ``new'' requirements contracts.
---------------------------------------------------------------------------

    \645\ FERC Stats. & Regs. at 31,809-814; mimeo at 510-24.
    \646\ We explained that if an existing requirements contract 
includes an explicit provision for payment of stranded costs or an 
exit fee, we will assume that the parties intended the contract to 
cover the contingency of the buyer leaving the system, and we will 
reject a stranded cost amendment to such a contract unless the 
contract permits renegotiation of the existing stranded cost 
provision or the parties to the contract mutually agree to a new 
stranded cost provision. Similarly, we said that we will reject a 
stranded cost amendment to an existing requirements contract if the 
contract prohibits stranded cost recovery (or precludes recovery for 
termination or reduction of service) or prohibits renegotiation of 
an existing stranded cost or exit fee provision, unless the parties 
to the contract mutually agree to a new stranded cost provision.
---------------------------------------------------------------------------

    We noted our desire that utilities attempt to renegotiate with 
their customers existing requirements contracts that do not contain 
exit fees or other explicit stranded cost provisions. If a contract is 
not renegotiated to add such a provision, we explained that, before the 
expiration of the contract: (1) A public utility or its customer may 
file a proposed stranded cost amendment to the contract under sections 
205 or 206; or (2) a public utility in a section 205 proceeding, or a 
transmitting utility in a section 211 proceeding, may file a proposal 
to recover stranded costs associated with any such existing contract 
through its transmission rates for a customer that uses the utility's 
transmission system to reach another generation supplier.
    We also concluded that, even if an existing requirements contract 
contains an explicit Mobile-Sierra <SUP>647 provision, it is in the 
public interest to permit the public utility to seek a unilateral 
amendment to add stranded cost provisions if the contract does not 
already contain exit fees or other explicit stranded cost 
provisions.<SUP>648 We explained why our determination that it is in 
the public interest to give public utilities a limited opportunity to 
propose contract changes unilaterally to address stranded costs if 
their contracts do not already explicitly do so satisfies the public 
interest standard of the Mobile-Sierra doctrine. We also indicated that 
customers with Mobile-Sierra contracts that do not explicitly address 
stranded costs may file complaints under section 206 of the FPA to 
propose to address stranded costs in existing requirements contracts.
---------------------------------------------------------------------------

    \647\ See United Gas Pipeline Company v. Mobile Gas Service 
Corporation, 350 U.S. 332 (1956); FPC v. Sierra Pacific Power 
Company, 350 U.S. 348 (1956).
    \648\ As a complement to our finding that, notwithstanding a 
Mobile-Sierra clause in an existing requirements contract, it is in 
the public interest to permit amendments to add stranded cost 
provisions to such contracts if the public utility proposing the 
amendment can meet the evidentiary requirements of this Rule, we 
concluded that customers under Mobile-Sierra contracts ought to have 
the opportunity to demonstrate that their contracts no longer are 
just and reasonable.
---------------------------------------------------------------------------

    We concluded that a public utility or its customer should be 
allowed to file a proposed stranded cost amendment, or a public utility 
or transmitting utility should be allowed to file a proposal to recover 
stranded costs through a departing generation customer's transmission 
rates, at any time prior to the expiration of the contract.

Rehearing Requests--July 11, 1994 Cut-Off Date

    Utilities For Improved Transition, repeating an argument raised in 
previous comments in this proceeding, objects to the Commission's July 
11, 1994 cut-off date for distinguishing between ``existing'' and 
``new'' requirements contracts. It argues that stranded cost recovery 
should be assured for all contracts executed before the effective date 
of the Rule (i.e., July 9, 1996), not just those executed before July 
11, 1994. It asserts that parties to contracts executed after July 11, 
1994 but before July 9, 1996 should have the same opportunity as 
parties to pre-July 11, 1994 contracts to offer evidence as to their 
reasonable expectations. Utilities For Improved Transition asserts that 
agencies may not promulgate retroactive rules without express statutory 
authority,<SUP>649 and that the FPA does not give the Commission such 
statutory authority.
---------------------------------------------------------------------------

    \649\ Citing Motion Picture Association of America v. Oman, 969 
F.2d 1154 (1992); Bowen v. Georgetown University Hospital, 488 U.S. 
204 (1988).
---------------------------------------------------------------------------

    Puget raises a somewhat different point. It notes that the 
definition of a ``new'' requirements contract as ``any wholesale 
requirements contract * * * extended or renegotiated to be effective 
after July 11, 1994'' (emphasis added) was not proposed until March 29, 
1995 (in the supplemental stranded cost NOPR). Puget states that the 
initial stranded cost NOPR proposed to give a utility three years from 
the date of Federal Register publication of the final stranded cost 
rule to negotiate or to file for stranded cost recovery. According to 
Puget, the March 1995 supplemental stranded cost NOPR proposed a 
retroactive change by defining a contract executed prior to July 11, 
1994 but extended or renegotiated to be effective after that date as a 
``new'' contract and by removing the three-year window for negotiating 
stranded cost recovery. By this change, Puget argues that the extension 
of a contract between the date of Federal Register publication of the 
initial NOPR (July 11, 1994) and the issuance of the supplemental NOPR 
(March 29, 1995) may have converted it into a ``new'' rather than an 
``existing''

[[Page 12401]]

contract for stranded cost recovery purposes. Puget asks the Commission 
to revise the definition of ``existing wholesale requirements 
contract'' in Order No. 888 and 18 CFR 35.26 to include contracts 
executed on or before July 11, 1994 that were extended prior to the 
issuance of the supplemental stranded cost NOPR (March 29, 1995) and 
for which stranded cost provisions were filed with the Commission prior 
to issuance of Order No. 888. Puget submits that failure to do so would 
be arbitrary and capricious and would deprive utilities with such 
contracts of adequate notice of a proposed rule.<SUP>650
---------------------------------------------------------------------------

    \650\ Puget notes that it executed a letter agreement with the 
Port of Seattle on January 12, 1995 to continue in place the terms 
of an existing contract until February 2, 1996, or the execution of 
a new agreement, whichever was earlier. It says that the parties 
were working within the context of the initial stranded cost NOPR, 
which would have given Puget three years from the date of the 
publication of the final rule to negotiate or file for stranded cost 
recovery. However, based on the definition of ``new'' contract in 
the Supplemental NOPR, the extension of the Puget/Port of Seattle 
contract may have converted it into a ``new'' rather than an 
``existing'' contract for stranded cost recovery purposes. Puget 
states that it filed an amendment to the contract on December 28, 
1995, that included stranded cost recovery provisions. Those 
provisions are pending in Docket Nos. ER96-714-000 and ER96-697-000. 
On January 10, 1997, the presiding judge issued an Initial Decision 
in Docket No. ER96-714-001 finding that Puget, by executing the 
January 1995 letter agreement, had not waived its eligibility to 
recover stranded costs. See Puget Sound Power & Light Company, 78 
FERC para. 63,001 (1997).
---------------------------------------------------------------------------

Commission Conclusion

    We will reject Utilities For Improved Transition's rehearing 
request because we believe that we adequately explained in Order No. 
888 why adoption of the July 11, 1994 cut-off date is appropriate and 
does not constitute retroactive rulemaking. We said in Order No. 888 
that because all parties were put on notice in the initial stranded 
cost NOPR that July 11, 1994 would be the operable date for the 
``existing''/``new'' contract distinction, utilities that executed 
requirements contracts after that date could have had no reasonable 
expectation that they would be permitted to recover any costs extra-
contractually. Moreover, we explained that because the costs at issue 
are extra-contractual costs, the Commission's notice to all parties 
that contracts executed after July 11, 1994 (the date that the initial 
NOPR was published in the Federal Register) will be enforced by their 
terms as far as stranded cost recovery is concerned does not constitute 
``retroactive rulemaking.'' The Commission has merely put all parties 
on notice that the opportunity for extra-contractual stranded cost 
recovery would not be available for any requirements contracts executed 
after July 11, 1994.
    The July 11, 1994 date is appropriate because it is the date on 
which all interested parties were given notice in the Federal Register 
that the recoverability of stranded costs for contracts executed on or 
before that date that did not provide for such recovery was at issue. 
The parties to requirements contracts executed after July 11, 1994 have 
been free to provide for stranded cost recovery in the contract, or 
not. The point is that, for requirements contracts executed after the 
cut-off date, stranded cost recovery will be governed solely by the 
terms of the contract.
    We believe that Puget has raised a valid point concerning the 
potential impact of the Commission's decision in the March 29, 1995 
supplemental stranded cost NOPR to treat extensions or renegotiations 
of existing contracts as ``new'' contracts for stranded cost purposes 
on parties that extended or renegotiated an existing contract prior to 
March 29, 1995. However, we expect that the situation described by 
Puget may be an isolated instance. On this basis, we do not believe it 
necessary to modify the definition of ``existing wholesale requirements 
contracts'' in Order No. 888 and 18 CFR 35.26 as requested by Puget. 
Nevertheless, we clarify that we will consider on a case-by-case basis 
whether to waive the provisions of 18 CFR 35.26 and to treat a contract 
extended or renegotiated (without adding a stranded cost provision) to 
be effective after July 11, 1994 but before March 29, 1995 as an 
existing contract for stranded cost purposes.<SUP>651
---------------------------------------------------------------------------

    \651\ As discussed in note 650, supra, the presiding judge in 
Docket No. ER96-714-001 recently issued an Initial Decision finding 
that Puget did not waive its eligibility to recover stranded costs 
when it entered into a January 1995 letter agreement with the Port 
of Seattle extending the term of the parties' 25-year sales contract 
for up to one year to accommodate further negotiations. Puget Sound 
Power & Light Company, 78 FERC para. 63,001 (1997).
---------------------------------------------------------------------------

Rehearing Requests--Mobile-Sierra

    Several entities challenge the Commission's generic Mobile-Sierra 
public interest finding. According to APPA, the Commission cannot make 
the public interest determination in a generic rulemaking, whether for 
stranded cost or non-stranded cost modifications.
    A number of entities object that the Commission does not identify 
any utilities whose existence is jeopardized without full wholesale 
stranded cost recovery.<SUP>652 PA Munis and APPA assert that vague 
allegations of harm if utilities do not recover stranded costs do not 
satisfy the public interest standard which they view to be 
``practically insurmountable.'' <SUP>653 American Forest & Paper 
contends that there is not one fact to support the Commission's 
assumption about threats to the financial stability of the electric 
utility industry. ELCON submits that significant retail stranded cost 
exposure does not justify the rule on wholesale stranded cost recovery.
---------------------------------------------------------------------------

    \652\ See, e.g., ELCON, PA Munis, APPA.
    \653\ See also ELCON.
---------------------------------------------------------------------------

    VT DPS and Valero submit that the Commission has not explained how 
allowing utilities to abrogate their contracts to extract exit fees 
from former customers vindicates any public interest. They argue that 
even assuming that wholesale customers depart en mass, the customers 
can only do so as their contracts expire; thus, the exodus, if it 
occurs, will be a trickle, not a flood. VT DPS and Valero maintain that 
even if some utilities were put at risk, it would not justify a generic 
rule. They contend that based on AGD v. FERC,<SUP>654 a generic 
solution is not proper for a problem existing only in ``isolated 
pockets.''
---------------------------------------------------------------------------

    \654\ 824 F.2d at 1019.
---------------------------------------------------------------------------

    PA Munis submits that, even assuming that the financial integrity 
of some utilities may be threatened, the missing link in the 
Commission's logic for a generic rule is that there is no protection 
for customers having Mobile-Sierra contracts with public utilities that 
are not faced with financial problems or cost shifting to third parties 
as a result of the open access requirements. PA Munis asserts that, at 
a minimum, each utility having Mobile-Sierra contracts should be 
required to show on an individual basis that the public interest 
standard has been satisfied.
    American Forest & Paper argues that Order No. 888 is not made even-
handed by allowing requirements customers to also challenge fixed-rate, 
fixed-term contracts. It submits that letting a customer file to amend 
a contract only as long as that amendment also addresses stranded costs 
is a ``heads you win, tails I lose'' proposition for the customer.
    APPA and TDU Systems request clarification of the scope of the 
Commission's decision to allow a utility ``to seek modification of 
contracts that may be beneficial to the customer'' if the customer is 
permitted to argue for modification of existing contracts that are 
less-favorable to it than other generation alternatives. APPA expresses 
concern that this language could be interpreted to mean that once a

[[Page 12402]]

customer seeks modification of stranded cost provisions in an existing 
contract, the utility may be able to challenge its entire contract with 
the customer. If this means the utility can modify contract provisions 
unrelated to stranded costs, APPA submits that the Commission has 
failed to address the Mobile-Sierra public interest issues associated 
with modifying non-stranded cost provisions in an existing contract. If 
not, APPA contends that the Commission should clarify the language. 
APPA objects that the Commission has not placed any limits on the types 
of modifications that a selling utility can make, nor specified the 
types of changes that it thinks a utility will likely make. It states 
that the Commission needs to explain why joint modification by both the 
seller and the purchaser can meet the public interest standard. 
According to APPA, the Commission has not explained the need for 
symmetrical treatment of contracts negotiated at a time when the 
Commission has found that the supplying public utilities were 
exercising their monopoly over transmission facilities in an unduly 
discriminatory manner.
    APPA also contends that the Commission's reliance on Northeast 
Utilities <SUP>655 is misplaced because that case involved the 
Commission's review of a newly-filed contract, as opposed to subsequent 
review of a contract previously accepted and approved by the 
Commission. APPA further asserts that Northeast Utilities involved an 
affiliate transaction, whereas this rulemaking is targeted at arm's-
length agreements between unrelated selling and purchasing utilities. 
According to APPA, this rulemaking does not present any of the concerns 
at issue in an affiliate transaction, and the Commission should have 
applied the ``practically insurmountable'' public interest standard 
doctrine from Papago, the classic ``low-rate'' case.
---------------------------------------------------------------------------

    \655\ Northeast Utilities Service Company v. FERC, 55 F.3d 686 
(1st Cir. 1995) (Northeast Utilities).
---------------------------------------------------------------------------

Commission Conclusion

    We disagree with those entities that argue that the Commission 
cannot make the public interest determination in a generic rulemaking. 
It is well established that it is within the Commission's discretion to 
decide whether we act through rule or through case-by-case 
adjudications.<SUP>656 As we explained in Order No. 888, we believe it 
is appropriate that our public interest finding be made on a generic 
basis given the fact that, by this Rule, we are requiring full open 
access that could significantly affect historical relationships among 
traditional utilities and their customers and the ability of utilities 
to recover prudently incurred costs.
---------------------------------------------------------------------------

    \656\ See Order No. 888, FERC Stats. & Regs. at 31,679; mimeo at 
127-28.
---------------------------------------------------------------------------

    At the same time, however, we are not eliminating the need for 
case-by-case demonstrations that stranded cost recovery should be 
allowed. Our public interest finding is that utilities be permitted to 
seek extra-contractual recovery of stranded costs in certain defined 
circumstances and that they be allowed to recover stranded costs only 
if they make a case-specific demonstration.
    Our holding applies only to wholesale requirements contracts (with 
Mobile-Sierra clauses) executed on or before July 11, 1994 that do not 
contain an exit fee or other explicit stranded cost provision. We will 
not permit modification of any contract that addresses the stranded 
cost issue explicitly, unless the contract specifically permits such 
modifications. Instead, we are examining requirements contracts that do 
not clearly address the issue in the context of the traditional 
regulatory regime under which they were signed--a regulatory 
environment in which it was assumed as a matter of course that the 
great majority of requirements customers would stay with their original 
suppliers and that these suppliers had a concomitant obligation to plan 
to supply these customers' continuing needs.
    Further, utilities with Mobile-Sierra contracts that seek recovery 
of stranded costs will have the burden, on a case-by-case basis, of 
showing they had a reasonable expectation of continuing to serve the 
departing generation customer. Although we have decided on a generic 
basis that it is in the public interest to permit public utilities with 
Mobile-Sierra contracts to make unilateral filings, we are not 
automatically approving any amendment that a particular utility might 
file. If a public utility unilaterally files a proposed stranded cost 
amendment under either section 205 or 206 of the FPA, this does not 
necessarily mean that the Commission will find it appropriate to allow 
such amendment. In addition, customers with Mobile-Sierra contracts 
that do not explicitly address stranded costs may also file complaints 
under section 206 of the FPA to propose to address stranded costs in 
existing requirements contracts. The Commission will analyze any 
proposed stranded cost amendment to a Mobile-Sierra contract, whether 
proposed by the utility or by its customer, based on the particular 
circumstances surrounding that contract. Thus, the case-by-case 
findings that some commenters seek will, in effect, be made when the 
Commission determines whether to approve a proposed stranded cost 
amendment to a particular contract.<SUP>657
---------------------------------------------------------------------------

    \657\ Because the Commission's public interest finding only 
applies to utilities that would seek to amend their contracts to add 
stranded cost provisions (not to those that face no stranded cost 
exposure and thus no need to amend their contracts to add stranded 
cost provisions), we reject as misplaced PA Munis' claim that there 
is no protection for customers having Mobile-Sierra contracts with 
public utilities that are not faced with financial problems or cost 
shifting to third parties as a result of the open access 
requirements.
---------------------------------------------------------------------------

    Although several entities have raised various challenges to the 
sufficiency of the Commission's public interest finding, we believe 
that we have satisfied the public interest standard by showing how 
third parties may ultimately bear the burden if public utilities with 
Mobile-Sierra contracts are not given any opportunity to propose 
contract changes to address stranded costs.<SUP>658 As we explained in 
Order No. 888, if the Commission fails to give a public utility this 
opportunity, and the utility's financial ability to continue the 
provision of safe and reliable service is impaired, third parties 
(customers relying on the public utility for their electric service) 
will be placed at risk. Similarly, if the Commission fails to give a 
public utility the opportunity to directly assign costs to the 
customers on whose behalf they were incurred, and some of the utility's 
customers leave the utility's generation system for that of another 
supplier without paying such costs, third parties (the utility's 
remaining customers) may be harmed by having to bear costs that were 
not incurred to serve them and that are stranded by the other 
customers' departures via open access transmission. We believe that 
protective action in the public interest is particularly necessary 
where, as here, a utility's rates could become insufficient because of 
fundamental changes in the industry that largely result from 
legislative or regulatory changes that could not be anticipated.
---------------------------------------------------------------------------

    \658\ As noted above, this finding applies only to wholesale 
requirements contracts with Mobile-Sierra clauses if the contracts 
were executed on or before July 11, 1994 and do not contain an exit 
fee or other explicit stranded cost provision.
---------------------------------------------------------------------------

    In response to those entities that contend that speculation of 
financial jeopardy or generalized statements of what may occur without 
reference to particular public utilities is not sufficient to satisfy 
the public interest standard, we disagree. The Commission need not make 
findings about particular utilities because the Rule does not

[[Page 12403]]

award stranded costs--it simply sets out generic criteria for 
determining recovery in a particular case. If a utility does not meet 
the criteria, there will be no stranded cost recovery. The public 
interest determination rests on the obvious conclusion that the failure 
of a utility to recover costs prudently incurred and financed based on 
investor expectation of traditional cost recovery clearly adds 
regulatory risk that investors reasonably did not expect.
    VT DPS's and Valero's reliance on AGD as support for the 
proposition that, even if some utilities were put at risk, a generic 
solution is not proper for a problem existing only in ``isolated 
pockets'' is misplaced. The AGD court found that the Commission had not 
adequately justified its decision to give all bundled firm sales 
customers of a pipeline that decided to offer service under Order No. 
436 the option to reduce their contract demand by 100 percent. In 
noting the lack of support for ``an industry-wide solution for a 
problem that exists only in isolated pockets,'' the court expressed 
concern that the remedy adopted by the Commission (``such drastic 
action as 100% CD reduction'' <SUP>659) was too broad.
---------------------------------------------------------------------------

    \659\ 824 F.2d at 1019.
---------------------------------------------------------------------------

    In Order No. 888, in contrast, the Commission has determined that 
it is in the public interest to give a limited class of utilities--
those that are parties to wholesale requirements contracts that were 
executed on or before July 11, 1994 that do not contain an exit fee or 
other explicit stranded cost provision and that contain Mobile-Sierra 
clauses--an opportunity to seek to add a stranded cost provision to the 
contract. Thus, the narrow scope of the Commission's Mobile-Sierra 
public interest finding is a far cry from the broad remedy (100 percent 
CD reduction) that the court remanded in AGD. Indeed, it more closely 
resembles the type of limited generic action that the AGD court 
suggested would be proper when it stated: ``This is not to say, of 
course, that the Commission could not use generic rules to identify a 
limited class of LDCs to be entitled to reduce CD when special 
conditions are present.''<SUP>660
---------------------------------------------------------------------------

    \660\ Id. at 1019-20.
---------------------------------------------------------------------------

    We explained in Order No. 888 that we were making two complementary 
public interest findings. First, as described above, is our decision 
that it is in the public interest to permit public utilities to seek 
stranded cost amendments to existing requirements contracts with 
Mobile-Sierra clauses. Second, we found that a ``party'' to a 
requirements contract containing a Mobile-Sierra clause no longer will 
have the burden of establishing independently that it is in the public 
interest to permit the modification of such contract, but still will 
have the burden of establishing that such contract no longer is just 
and reasonable and therefore ought to be modified. We clarify that, in 
making this second finding, our reference to a ``party'' to a 
requirements contract containing a Mobile-Sierra clause was directed at 
modification of contract provisions by customers.<SUP>661 Additionally, 
this second finding applies to any contract revisions sought, whether 
or not they relate to stranded costs.<SUP>662
---------------------------------------------------------------------------

    \661\ We note that the fact that a contract may bind a utility 
to a Mobile-Sierra standard does not mean that the customer is also 
bound to that standard. Unless a customer specifically waives its 
section 206 just and reasonable rights, the Commission construes the 
issue in favor of the customer.
    \662\ In situations in which a customer institutes a section 206 
proceeding to modify a contract that binds the utility to a Mobile-
Sierra standard, the utility may make whatever arguments it wants 
regarding any of the contract terms, including those unrelated to 
stranded costs, but will be bound to a Mobile-Sierra standard for 
contract terms that do not relate to stranded costs.
---------------------------------------------------------------------------

    We also concluded that ``if a customer is permitted to argue for 
modification of existing contracts that are less favorable to it than 
other generation alternatives, then the utility should be able to seek 
modification of contracts that may be beneficial to the customer.'' 
<SUP>663 We clarify in response to APPA and TDU Systems that this 
statement was not intended to imply that the Commission had made 
Mobile-Sierra findings that would permit utilities with Mobile-Sierra 
contracts to seek non-stranded cost amendments to contracts that may be 
favorable to a customer, based on a showing that the contracts are no 
longer just and reasonable. Our Mobile-Sierra findings as to public 
utility sellers apply only when utilities seek to add stranded cost 
provisions or make other modifications related to stranded costs. Thus, 
if a utility with a Mobile-Sierra contract initiates a section 206 
proceeding in which it seeks to modify contract provisions that do not 
relate to stranded costs, it will have to show that it is contrary to 
the public interest not to modify the contract.
---------------------------------------------------------------------------

    \663\ FERC Stats. & Regs. at 31,664, 31,813; mimeo at 86, 521.
---------------------------------------------------------------------------

    As we stated in Order No. 888, the most productive way to analyze 
contract modification issues is to consider simultaneously both the 
selling public utility's claims, if any, that it had a reasonable 
expectation of continuing to serve the customer beyond the term of the 
contract and the customer's claim, if any, that the contract no longer 
is just and reasonable and therefore ought to be modified. We said that 
if a customer brings a claim in a section 206 proceeding to shorten or 
terminate a contract, the selling public utility must bring any 
stranded cost claim with respect to that customer in that section 206 
proceeding. Our goal is to ensure that all of the issues expected to be 
raised by the parties when a customer departs a utility's generation 
system can be efficiently litigated in one proceeding. Therefore, we 
have similarly required that if the customer intends to claim that the 
notice or termination provision of its existing requirements contract 
is unjust and unreasonable, it must present that claim in any 
proceeding brought by the selling public utility to seek recovery of 
stranded costs. We disagree with American Forest & Paper's argument 
that it is a ``no-win'' situation if a customer seeking to modify a 
contract must present that claim in any stranded cost proceeding 
brought by the selling public utility. To the contrary, providing the 
customer to a Mobile-Sierra contract with the opportunity to 
demonstrate that its contract is no longer just and reasonable and that 
its term should be shortened or eliminated could be beneficial to the 
customer, notwithstanding the customer's potential stranded cost 
obligation. As we explained in the Rule:
    [G]iven the industry circumstances now facing us, both selling 
utilities and their customers ought to have an opportunity to make 
the case that their existing requirements contracts ought to be 
modified. By providing both buyers and sellers this opportunity, the 
Commission attempts to strike a reasonable balance of the interests 
of all market participants.<SUP>[664]]
---------------------------------------------------------------------------

    \664\ FERC Stats. & Regs. at 31,814; mimeo at 522-23.

    In response to APPA's analysis of Northeast Utilities, it is true, 
as APPA asserts, that Northeast Utilities involved the Commission's 
initial review of a contract, not modification of a previously accepted 
and approved contract, and that the contract involved an affiliate 
transaction, while this rulemaking is targeted at arm's-length 
agreements. However, we do not believe that these differences bear on 
the precedential value of this case to the circumstances presented in 
the Rule. To the contrary, we believe that Northeast Utilities provides 
valuable guidance concerning application of the public interest 
standard where, as here, a failure to allow limited contract 
modification may harm the public interest by harming third parties.
    We disagree with APPA's contention that the Commission should have 
applied the ``practically

[[Page 12404]]

insurmountable'' standard from ``the classic `low-rate' case, namely, 
Papago.''<SUP>665 As we have stated on several occasions, ``we do not 
interpret the public interest standard of review * * * as imposing on 
us a practically insurmountable burden in situations in which we are 
protecting non-parties to a contract.'' <SUP>666 Additionally, we do 
not interpret the public interest standard as practically 
insurmountable in extraordinary situations such as this one where 
historic statutory and regulatory changes have converged to 
fundamentally change the obligations of utilities and the markets in 
which they and their customers will operate. In this circumstance, we 
believe the public interest test is met where the Commission determines 
that it is necessary to allow parties to seek contract amendments in 
order to protect the stability and financial integrity of the electric 
industry in general during the transition to competition as well as the 
interest of third parties affected by the transition. This type of 
situation simply was not addressed in Papago.
---------------------------------------------------------------------------

    \665\ APPA at 49. It should be noted that, as the Northeast 
Utilities court indicated, the Papago court's description of the 
public interest standard as ``practically insurmountable'' was 
dictum. 55 F.3d at 691. Further, Papago did not involve a 
contractual arrangement for rate revision where the parties ``by 
broad waiver * * * eliminate both the utility's right to make 
immediately effective rate changes under Sec. 205 and the 
Commission's power to impose changes under Sec. 206, except the 
indefeasible right of the Commission under Sec. 206 to replace rates 
that are contrary to the public interest.'' Papago, 723 F.2d at 953. 
Instead, Papago involved a contractual regime that ``contractually 
eliminate[d] the utility's right to make immediately effective rate 
changes under Sec. 205 but [left] unaffected the power of the 
Commission under Sec. 206 to replace not only rates that are 
contrary to the public interest but also rates that are unjust, 
unreasonable, or unduly discriminatory or preferential to the 
detriment of the contracting purchaser.'' Id. See also id. at 953-
54.
    \666\ Southern Company Services, Inc., 67 FERC para. 61,080 at 
61,228 (1994); see also Florida Power & Light Company, 67 FERC para. 
61,141 at 61,398-99 (1994).
---------------------------------------------------------------------------

    Congress has entrusted the Commission with the statutory 
responsibility to protect the public interest. As we explained in 
Northeast Utilities Service Company: <SUP>667

    \667\ 66 FERC para. 61,332 at 62,081, reh'g denied, 68 FERC 
para. 61,041 (1994).
---------------------------------------------------------------------------

    Protection of the `public interest' provides the justification 
for the Commission's power to regulate public utilities under Part 
II [of the FPA]. Specifically, section 201(a) of the FPA declares 
`that the business of transmitting and selling electric energy for 
ultimate distribution to the public is affected with a public 
interest' and that federal regulation of matters related to 
generation (to the extent provided in Parts II and III of the FPA) 
and of the transmission and sale at wholesale of electric energy in 
interstate commerce `is necessary in the public interest.'

Consistent with our statutory obligations under the FPA, the Commission 
has an overriding responsibility to protect non-parties affected by 
Mobile-Sierra contracts, including consumers, to ensure that matters 
entrusted to our jurisdiction function smoothly during the 
restructuring transition, and to fairly balance the interests of 
utilities and customers during the transition. <SUP>668 The ability to 
meet our overarching public interest responsibilities would be 
virtually precluded if we must apply a practically insurmountable 
standard of review before we can take action to address industry-wide 
transition issues.
---------------------------------------------------------------------------

    \668\ 66 FERC at 62,081-83; see also Southern, 67 FERC at 
61,228-29.
---------------------------------------------------------------------------

Rehearing Requests Supporting Limited Transition Period

    Several entities request rehearing of the Commission's decision not 
to establish a three-to five-year period within which stranded cost 
recovery could be raised. They assert that if the Commission truly 
views stranded investment as a transition process, the transition 
should not be an extended one.<SUP>669
---------------------------------------------------------------------------

    \669\ E.g., Central Montana EC, Central Illinois Light.
---------------------------------------------------------------------------

Commission Conclusion

    The Commission will deny the requests for rehearing on this point. 
As we explained in Order No. 888, although we considered limiting the 
period within which stranded cost recovery could be raised, there is no 
uniform time remaining on requirements contracts executed on or before 
July 11, 1994. <SUP>670 As a result, any limitation on the period in 
which parties could propose amendments covering stranded costs, such as 
three years, would affect market participants unequally. Those with 
long terms remaining on their contracts could object that immediately 
addressing the issue would not be cost effective. A utility with a long 
remaining term might not even seek stranded cost recovery depending on 
the competitive value of its assets near the end of the contract 
term.<SUP>671 However, such a utility would invariably seek to preserve 
its option to seek stranded cost recovery if its failure to do so 
within a short period resulted in a waiver of its right to do so. 
Having determined that it is generally appropriate to leave in place 
existing requirements contracts, it is not then reasonable to create a 
time limitation on stranded cost recovery that would encourage a 
supplier to seek early termination in order to preserve its stranded 
cost recovery rights.
---------------------------------------------------------------------------

    \670\ It is not possible for the Commission to come up with a 
reliable yardstick of the remaining terms of existing requirements 
contracts. The Commission's files do not categorize rate schedules 
as requirements, coordination and transmission-only contracts. 
Moreover, there is no uniform format for requirements contracts. 
Many have evergreen provisions, the terminology of which varies from 
contract-to-contract (e.g., some may be year-to-year, others may 
roll over).
    \671\ The value of its assets could vary over time as new 
technologies emerge, fuel costs fluctuate, or environmental 
requirements change.
---------------------------------------------------------------------------

    On this basis, we believe that we have adequately explained the 
rationale for our decision to allow stranded cost claims to be raised 
at any time prior to the termination of the contract, instead of within 
three to five years of the effective date of the Rule.
6. Recovery of Stranded Costs Caused by Retail-Turned-Wholesale 
Customers
    In Order No. 888, we concluded that this Commission should be the 
primary forum for addressing the recovery of stranded costs caused by a 
retail-turned-wholesale customer.<SUP>672 We stated that if such a 
customer is able to reach a new generation supplier because of the new 
open access (through the use of a FERC-filed open access transmission 
tariff or through transmission services ordered pursuant to section 211 
of the FPA), any costs stranded as a result of this wholesale 
transmission access should be viewed as ``wholesale stranded costs.'' 
We explained that there is a clear nexus between the FERC-
jurisdictional transmission access requirement and the exposure to non-
recovery of prudently incurred costs and that, in these circumstances, 
this Commission should be the primary forum for addressing recovery of 
such costs. <SUP>673
---------------------------------------------------------------------------

    \672\ FERC Stats. & Regs. at 31,818-19; mimeo at 534-37.
    \673\ We indicated that we will require the same evidentiary 
demonstration for recovery of stranded costs from a retail-turned-
wholesale customer (and will apply the same procedures for 
determining stranded cost obligation) as that required in the case 
of a wholesale requirements customer.
---------------------------------------------------------------------------

    We said we will not be the primary forum for stranded cost recovery 
in situations in which an existing municipal utility annexes territory 
served by another utility or otherwise expands its service territory. 
We indicated that in these situations there is no direct nexus between 
the FERC-jurisdictional transmission access requirement and the 
exposure to non-recovery of prudently incurred costs. The risk of an 
existing municipal utility expanding its territory was a risk prior

[[Page 12405]]

to the Energy Policy Act and prior to any open access requirement.
    Nevertheless, we did express concern that there may be 
circumstances in which customers and/or utilities could attempt, 
through indirect use of open access transmission, to circumvent the 
ability of any regulatory commission--either this Commission or state 
commissions--to address recovery of stranded costs. We reserved the 
right to address such situations on a case-by-case basis.

Rehearing Requests Opposing Retail-Turned-Wholesale Jurisdiction

    A number of entities challenge the Commission's assertion that 
costs associated with retail-turned-wholesale customers would not be 
stranded but for the FERC-jurisdictional transmission access 
requirement. They assert that the condition precedent to 
municipalization is the operation of a state process, and thus that it 
cannot be the case that the recovery of costs caused by a retail-
turned-wholesale customer is ``not subject to regulation by the 
States.'' They submit that such costs would not be stranded but for the 
action of state legislators or state regulators in granting authority 
for the customer's status change. They argue that any nexus that the 
Commission's authority under the FPA has to wholesale transmission 
services subsequently provided to the new wholesale customer is 
entirely derivative of the state's action.<SUP>674
---------------------------------------------------------------------------

    \674\ E.g., NARUC, TAPS, Nucor, Suffolk County, IL Com, Multiple 
Intervenors, APPA, CAMU, WI Com, NASUCA.
---------------------------------------------------------------------------

    A number of entities argue that jurisdiction over costs that are 
stranded when a retail customer becomes a wholesale customer should be 
left to the states because the facilities used to provide retail 
service to these retail customers were subject to state jurisdiction 
and were included in retail rate base when the service was 
rendered.<SUP>675 They argue that because the Commission had no 
jurisdiction over the public utility facilities and costs incurred to 
serve retail-turned-wholesale customers, it has no jurisdiction to 
address those public utility costs if they become stranded. Thus, 
according to these entities, the conversion of the customer from retail 
to wholesale does not simultaneously effectuate a conversion of the 
costs from retail to wholesale.
---------------------------------------------------------------------------

    \675\ E.g., ELCON, IL Com, IN Com, American Forest & Paper, AR 
Com, MO/KS Coms, NJ BPU, Suffolk County, WY Com, VA Com, FL Com, 
NARUC, TAPS.
---------------------------------------------------------------------------

    AR Com and MO/KS Coms submit that jurisdiction over the costs 
incurred for historical retail customers does not shift unless the 
parties themselves make those costs a part of their new wholesale 
contract. NY Com submits that the Commission should recognize the 
states' jurisdiction to set the level of stranded costs associated with 
retail-turned-wholesale customers to be recovered in wholesale 
transmission rates set by FERC. FL Com asserts that state authorities 
are in a better position to assess the extent of stranded facilities 
and their costs, and that the Commission's involvement should be 
limited to that requested by a state by petition.
    OH Com states that the Commission's position on stranded costs 
associated with retail-turned-wholesale customers invites second-
guessing of state commission determinations and encourages forum 
shopping by introducing more than one stranded cost treatment within a 
single state jurisdiction. It expresses concern that utilities may seek 
to creatively disaggregate into generation, transmission, and 
distribution companies in ways to deliberately recast traditional 
retail relationships as wholesale in an effort to obtain favorable 
regulatory treatment of stranded costs.
    IN Com submits that Order No. 888's treatment of stranded costs 
associated with retail-turned-wholesale customers will discourage state 
legislatures from making municipalization more available. VT DPS and 
Valero argue that the threat of a stranded cost surcharge will erect a 
new barrier to the formation of municipal utilities. They note that the 
Rule refers to one commenter's observation that, if Otter Tail could 
have made a stranded cost claim against the municipal utility that 
Elbow Lake planned to create, Otter Tail would not have needed to 
refuse to wheel and there would never have been an Otter Tail case. 
They submit that the Commission never addressed whether, or why, it 
believed the point to be wrong.
    VT DPS and Valero also assert that the Rule represents a major 
inconsistency with prior Commission treatment of municipalization. They 
submit that the Commission historically promoted franchise competition 
between municipalities and utilities by holding tariff provisions that 
restrict such competition to be anticompetitive and 
unreasonable.<SUP>676
---------------------------------------------------------------------------

    \676\ VT DPS and Valero cite in this regard Florida Power & 
Light Company, 8 FERC para. 61,121 (1979); Power Authority of the 
State of New York v. FERC, 743 F.2d 93 (2d Cir. 1984); Metropolitan 
Transportation Authority v. FERC, 796 F.2d 584 (2d Cir. 1986).
---------------------------------------------------------------------------

    American Forest & Paper submits that recovery of 100 percent of 
stranded costs caused by municipalization is inconsistent with the 
Commission's actions in the natural gas industry, where the Commission 
has encouraged competition at the retail level through competitive 
bypass and has not created barriers to competitive entry by imposing 
transition charges or exit fees on converting customers.<SUP>677
---------------------------------------------------------------------------

    \677\ American Forest & Paper cites in support of its position 
Great Lakes Gas Transmission Limited Partnership, 68 FERC para. 
61,376 (1994).
---------------------------------------------------------------------------

    Nucor objects that the Rule does not address the substantive 
findings, the common sense rationale, or the jurisdictional distinction 
drawn in United Illuminating.<SUP>678 It contends that the Commission's 
observation in Order No. 888 that there may not be a state regulatory 
forum for the recovery of stranded costs associated with retail-turned-
wholesale customers and hence that the Commission should be the primary 
forum for addressing such stranded costs is flawed because there always 
is a state forum to address such cost recovery (the adequacy of the 
relief provided is a very distinct issue) and open access transmission 
does not and cannot cause retail competition to occur.<SUP>679
---------------------------------------------------------------------------

    \678\ United Illuminating Company, 63 FERC para. 61,212, reh'g 
denied, 64 FERC para. 61,087 (1993) (United Illuminating).
    \679\ See also Suffolk County Rehearing (Commission's analysis 
in United Illuminating was correct; nothing has changed to warrant 
the Commission's rejection of that analysis).
---------------------------------------------------------------------------

Commission Conclusion

    We will reject the requests for rehearing of our decision to be the 
primary forum for addressing the recovery of stranded costs caused by 
retail-turned-wholesale customers. We find the requests for rehearing 
on this issue unpersuasive. While it may be the case, as some entities 
suggest, that state action is a condition precedent to 
municipalization, the rehearing petitions ignore the fact that the Rule 
covers situations in which open access is also a condition precedent to 
the municipalized customers leaving their existing supplier's system. 
Order No. 888 does not propose that the Commission be the primary forum 
for stranded cost recovery for all cases of municipalization. Instead, 
our holding is limited to those cases in which the new wholesale entity 
uses Commission-mandated transmission access to obtain new power supply 
on behalf of retail customers that were formerly supplied

[[Page 12406]]

power by the utility providing the transmission service.<SUP>680
---------------------------------------------------------------------------

    \680\ In the case of municipalization, the bundled retail 
customers of a local utility become the bundled retail customers of 
the new municipal utility. As explained above, we call this a 
``retail-turned-wholesale customer'' situation because the new 
municipal entity in effect ``stands in the shoes'' of the retail 
customers for purposes of obtaining wholesale transmission access 
and new power supply.
---------------------------------------------------------------------------

    As we explained in Order No. 888, in such cases there is a direct 
nexus between the FERC-jurisdictional transmission access requirement 
and the exposure to non-recovery of costs stranded as a result of this 
wholesale transmission access. Thus, the stranded costs associated with 
retail-turned-wholesale customers for which Order No. 888 provides an 
opportunity for recovery would not have been incurred but for the 
action of this Commission in requiring a utility to make unbundled 
transmission services available. In these cases, the former bundled 
retail customers of the historical supplying utility (now the bundled 
retail customers of the new municipal system) would not have obtained 
access to new power supply but for the Commission's order mandating 
transmission. Without the regulatory mandate to provide access, the 
utility would have indirectly continued sales to the same retail 
customers because the new municipal utility purchasing power on the 
retail customers' behalf would have had no way to reach other power 
suppliers. In this situation, there would be no stranded generation 
costs. In other words, the creation of a municipal utility intermediary 
to purchase power at wholesale would not, by itself, trigger stranded 
costs. Rather, it is the access from the historical supplier of the 
bundled retail customers that is the condition precedent to reaching 
other power suppliers and thereby triggering stranded costs. Therefore, 
there is a clear causal nexus between the stranded costs and the 
availability and use of the tariff required by the Commission.
    Costs that are exposed to nonrecovery when a retail customer or a 
newly-created wholesale power sales customer ceases to purchase power 
from the utility and does not use the utility's transmission system to 
reach a new generation supplier (e.g., through self-generation or use 
of another utility's transmission system) do not meet the definition of 
``wholesale stranded costs'' for which the Rule provides an opportunity 
for recovery. Such costs are outside the scope of the Rule because such 
costs would not be stranded as a direct result of the new open access.
    In response to the argument that conversion of a customer from 
retail to wholesale would not simultaneously effectuate a conversion of 
the costs from retail to wholesale, we believe this argument confuses 
the issue. We note that we have defined stranded costs as wholesale or 
retail on the basis of whether wholesale or retail open access is the 
cause of the costs being stranded, not on the basis of the original 
retail or wholesale characteristic of the costs. Thus, even though 
costs may have been originally incurred as retail-related costs, the 
precipitating event that results in such costs being stranded in the 
retail-turned-wholesale customer scenario is the use by the new 
wholesale customer of the Commission-mandated tariff. When a customer 
is able to use the Commission-required tariff to reach another 
generation supplier, it causes the utility to incur an economic cost in 
providing transmission service that is equal to the foregone revenues 
that the utility reasonably expected to receive under a state 
regulatory regime. Thus, because of the causal nexus between the use of 
a former supplying utility's Commission-mandated transmission tariff 
and the potential for foregone revenues by that utility as a result of 
the Commission-required access, the costs stranded by a retail-turned-
wholesale customer are properly viewed as economic costs that are 
jurisdictional to this Commission.
    In response to those entities that express concern that the 
Commission's position on stranded costs associated with retail-turned-
wholesale customers invites second-guessing of state commission 
determinations, we emphasize that we have assumed primary authority to 
address such costs only in a limited category of cases where there is a 
direct nexus between the availability of Commission-required open 
access and the stranding of costs when the former customer uses the 
former supplying utility's transmission system (through its open access 
tariff or a section 211 order) to reach a new supplier. We indicated in 
Order No. 888 that if the state has permitted any recovery from 
departing retail-turned-wholesale customers, such amount will not be 
stranded for purposes of this Rule. We will deduct that amount from the 
costs for which the utility will be allowed to seek recovery under this 
Rule from the Commission. In so doing, however, we are not second-
guessing the states as to what a utility may recover under state law. 
Additionally, we will give great weight in our proceedings to a state's 
view of what might be recoverable.
    We also reject the argument that the Commission's position on 
stranded costs associated with retail-turned-wholesale customers 
encourages forum shopping. To the contrary, as we said in Order No. 
888, to avoid forum shopping and duplicative litigation of the issue, 
we expect parties to raise claims before this Commission in the first 
instance. We believe that this Commission should be the primary forum 
because, without the open access provided by the Rule, the new 
municipal utility would not be able to reach a new supplier and, as a 
result, would not cause the utility to incur stranded costs (as defined 
in this Rule).
    We reject as misplaced arguments that the Rule represents a major 
inconsistency with the Commission's historical promotion of franchise 
competition between municipalities and utilities and that it will 
discourage municipalization.<SUP>681 It continues to be the 
Commission's policy to encourage competition. Indeed, the goal of Order 
No. 888 is to remove impediments to competition in the wholesale bulk 
power marketplace and to bring more efficient, lower cost power to the 
Nation's electricity consumers. However, the purpose of the stranded 
cost policy is neither to encourage nor to discourage municipalization, 
but rather to facilitate a fair transition to competition and to ensure 
stability in the industry during that transition. As we discuss 
elsewhere in this order, we believe that this Commission must address 
the recovery of the costs of moving from a monopoly-regulated regime to 
one in which all sellers can compete on a fair basis and in which 
electricity is more competitively priced. On this basis, we believe 
that if a new wholesale entity such as a municipal utility uses 
Commission-required open access to reach a new supplier on behalf of 
its retail customers (previously retail customers of the former 
supplier), the former supplying utility should be given an opportunity 
to recover legitimate, prudent and verifiable costs that it

[[Page 12407]]

incurred under the prior regulatory regime to serve that customer.
---------------------------------------------------------------------------

    \681\ In response to VT DPS and Valero, we note that whether or 
not Otter Tail may have agreed to wheel power for the municipal 
utility that Elbow Lake planned to create if Otter Tail could have 
made a stranded cost claim against that municipal utility is of no 
moment to the Commission's decision in Order No. 888 to allow 
utilities the opportunity to seek recovery of stranded costs 
associated with retail-turned-wholesale customers. The Court in 
Otter Tail did not address the stranded cost issue because it was 
not presented in that case. Nor was the Court presented with the 
extraordinary circumstances--the historic statutory and regulatory 
changes, including the requirement of open access, that have 
converged to fundamentally change the obligations of utilities and 
the markets in which they operate--that have justified this 
Commission's Order No. 888 stranded cost policy.
---------------------------------------------------------------------------

    In response to American Forest & Paper's argument that recovery of 
100 percent of stranded costs caused by municipalization is 
inconsistent with the Commission's policy in the natural gas industry 
of allowing competitive bypass without imposing transition charges or 
exit fees on converting customers, we note that industrial gas 
customers who bypass a local distribution company's (LDC) facilities do 
not escape transition costs quite so easily as suggested by American 
Forest & Paper. It is true that, when the end user bypasses the LDC to 
reach an interstate pipeline different from the pipeline serving the 
LDC, the Commission views the bypass as a risk of competition from 
which the LDC should not be shielded.<SUP>682 However, when the end 
user bypasses the LDC to reach the same interstate pipeline that serves 
the LDC, the Commission may take certain actions to minimize adverse 
effects on the LDC and its remaining customers.<SUP>683 Moreover, an 
end user that bypasses an LDC to reach the same pipeline that serves 
the LDC would, in any event, be allocated a share of the pipeline's gas 
supply realignment costs (if any), since those costs are allocated 
based on current contract demand (or usage).<SUP>684 Accordingly, we 
see no inconsistency between our bypass policy for the natural gas 
industry and Order No. 888's treatment of stranded costs associated 
with retail-turned-wholesale customers. Similar to our refusal to 
shield LDCs from the adverse effects of an end user's bypass to reach a 
different pipeline than serves the LDC, Order No. 888 does not provide 
an opportunity for stranded cost recovery where a retail-turned-
wholesale customer uses another utility's transmission system to reach 
a new supplier. As we note above, the opportunity for recovery of 
stranded costs associated with retail-turned-wholesale customers is 
limited to those cases in which the former retail customer obtains 
(either directly or through another wholesale transmission purchaser) 
unbundled transmission services from its former supplying utility. In 
the case of an end use customer bypassing the LDC to reach the same 
pipeline that serves the LDC, the end use customer would similarly be 
allocated a share of the pipeline's gas supply realignment costs. As a 
result, American Forest & Paper's attempt to rely on the Commission's 
gas bypass policy is misplaced.
---------------------------------------------------------------------------

    \682\ Texas Gas Transmission Corporation, 65 FERC para. 61,275 
(1993).
    \683\ Texas Gas Transmission Corporation, 69 FERC para. 61,245, 
reh'g, 70 FERC para. 61,207 (1995) (requiring pipeline to offer LDC 
a reduction in its contract demand).
    \684\ See Southern Natural Gas Company, 75 FERC para. 61,046 at 
61,158 (1996); Arcadian Corporation v. Southern Natural Gas Company, 
67 FERC para. 61,176 at 61,538 (1994). See also United Distribution 
Companies, 88 F.3d at 1181. As the United Distribution Companies 
court noted, the Commission has given an LDC relief (and required 
the bypassing customer to bear its share of transition costs) if the 
LDC can show a direct nexus between the bypass and the pipeline, 
although the Commission has declined to adopt a generic rule 
addressing this issue. 88 F.3d at 1180-81.
---------------------------------------------------------------------------

    We also disagree with those entities that argue that the Commission 
has failed to adequately distinguish Order No. 888's treatment of 
stranded costs associated with retail-turned-wholesale customers with 
the Commission's decision in United Illuminating. As we stated in Order 
No. 888, we recognize that we took a different approach to stranded 
cost recovery associated with retail-turned-wholesale customers in 
United Illuminating, where we suggested that state and local regulatory 
authorities or the courts should be able to provide an adequate forum 
to address retail franchise matters, including recovery of stranded 
costs caused by municipalization, but said we would consider revisiting 
the question if United Illuminating could demonstrate the lack of a 
forum.<SUP>685 However, we explained that since the issuance of that 
decision we have had an opportunity to re-analyze the nature of the 
stranded cost problem when a retail customer becomes a wholesale 
customer, including the potential that there might not be a state 
regulatory forum for recovery of such costs. In these circumstances, we 
have determined that where such costs are stranded as a direct result 
of Commission-mandated wholesale transmission access, these costs 
should be viewed as costs of the transition to competitive wholesale 
bulk power markets and this Commission should be the primary forum for 
addressing their recovery.
---------------------------------------------------------------------------

    \685\ 63 FERC at 62,583-84.
---------------------------------------------------------------------------

    In response to Nucor's objection that there always is a state forum 
to address stranded cost recovery associated with retail-turned-
wholesale customers, with the adequacy of the relief being a distinct 
issue, we clarify that our primary concern in retail-turned-wholesale 
situations is not whether there is an adequate state regulatory forum 
for the recovery of stranded costs associated with retail-turned-
wholesale customers. Rather, our primary concern is that wholesale 
customers (whether or not formerly retail) should be responsible for 
the costs incurred to meet their power needs that are stranded when 
they use the wholesale transmission ordered by this Commission to reach 
new suppliers. Our decision to be the primary forum in the case of 
stranded costs associated with retail-turned-wholesale customers is 
based on the causal nexus between regulatory-mandated wholesale 
transmission access and the stranding of costs when a new municipal 
utility uses such access to obtain new power supply on behalf of retail 
customers previously served by the former supplying utility.

Rehearing Requests Seeking Expansion of Retail-Turned-Wholesale 
Jurisdiction

    Other entities seek rehearing of the Commission's decision not to 
be the primary forum for stranded cost recovery in situations in which 
an existing municipal utility annexes territory served by another 
utility or otherwise expands its service territory.<SUP>686 A number of 
them argue that the loss of existing retail customers through municipal 
annexations or expansions is no different from the loss of retail 
customers through new municipalization because existing municipal 
systems are likely to use Commission-jurisdictional open access 
transmission to obtain resources to supply power to the annexed 
loads.<SUP>687 They submit that, just as with newly-municipalized 
customers, such costs would not be stranded but for the action of this 
Commission.
---------------------------------------------------------------------------

    \686\ E.g., EEI, SoCal Edison, Centerior, Atlantic City, PSE&G, 
Puget, Public Service Co of CO, Coalition for Economic Competition.
    \687\ E.g., EEI, SoCal Edison, PSE&G, Puget, Public Service Co 
of CO, Coalition for Economic Competition. Coalition for Economic 
Competition suggests, for example, that villages and large 
industrial customers may opt to join existing municipal systems 
that, in most cases, will use Commission-jurisdictional transmission 
tariffs to obtain resources to supply power to the annexed loads.
---------------------------------------------------------------------------

    Some of these entities express concern that the Rule will encourage 
retail-turned-wholesale transactions to be undertaken as annexations 
rather than through the formation of new entities to avoid stranded 
costs. <SUP>688 Public Service Co of CO contends that Order No. 888, in 
conjunction with the Commission's section 211 order in American 
Municipal Power Ohio, Inc.,<SUP>689 may facilitate municipal 
annexations by enabling municipal systems to serve new territory 
through the establishment of second delivery points.
---------------------------------------------------------------------------

    \688\ E.g., EEI, Coalition for Economic Competition, Atlantic 
City, Puget, Public Service Co of CO.
    \689\ 74 FERC para. 61,086, final order directing transmission 
service, 76 FERC para. 61,265 (1996).
---------------------------------------------------------------------------

    Coalition for Economic Competition and Puget also argue that the 
Commission must consider stranded

[[Page 12408]]

costs that arise from municipal expansion in order to satisfy its 
statutory obligation under the FPA to ``set just and reasonable'' 
rates. They contend that there is no justification for charging one 
rate to former retail customers taking transmission services through a 
new municipal utility and another rate to those taking service through 
municipal annexation or through use of another utility's transmission 
system.
    PSE&G suggests that the distinction between new municipalization on 
the one hand and municipal annexation or expansion on the other hand 
may lead to unnecessary controversy and litigation as entities wrangle 
over whether a given expansion/annexation is really an expansion or a 
municipalization. It says that a situation could arise where a 
municipality serves one town in order to serve thousands of additional 
customers in a second town. According to PSE&G, it is not clear from 
the Rule whether the Commission would consider this an expansion of a 
municipality's service territory or a new municipalization.
    Puget submits that the stranded cost recovery mechanism must not be 
subject to being frustrated by simple artifices such as having the new 
supplier (instead of the departing customer) request and contract for 
transmission service. SoCal Edison seeks clarification of the 
Commission's authority to mandate stranded cost recovery if a retail 
customer disconnects from a utility's system and accesses another 
generation supplier by interconnecting with a public power entity (who 
in turn would interconnect with a neighboring jurisdictional utility). 
It asks the Commission to clarify that such a transaction effectively 
constitutes a municipalization, not an expansion of a service 
territory, and that the Commission, under FPA section 211, can compel 
the recovery of stranded costs by having the ``new'' jurisdictional 
utility assess a stranded cost charge and pass the revenues on to the 
utility from whose system the customer departed.
    SoCal Edison seeks several additional clarifications. It states 
that it understands that the Commission's primary forum status in no 
way prevents or interferes with a state's authority to order stranded 
cost recovery from departing retail customers. If this is not the case, 
SoCal Edison seeks rehearing on this issue. SoCal Edison also asks the 
Commission to clarify that the Commission retains the discretion to 
defer to a state stranded cost calculation methodology if appropriate 
to do so on the facts of a particular case.

Commission Conclusion

    We have carefully reviewed the arguments made by petitioners 
seeking rehearing of our decision not to be the primary forum for 
stranded cost recovery in the case of municipal annexations. Based on 
that review we have decided to reconsider our decision. This conclusion 
is based in large part upon the very significant similarities between 
the creation of a new municipal utility system (also referred to as 
municipalization) and the expansion of an existing municipal utility 
system (e.g., through annexation of additional retail service 
territory). We recognize that the same nexus to Commission-required 
transmission access that forms the basis for our decision to allow a 
utility to seek stranded cost recovery in cases of new 
municipalization--use of the former supplying utility's transmission 
system--is likely to be present in some cases of municipal annexation. 
In the case of both new municipalizations and annexations, the bundled 
retail customers of a local utility become the bundled retail customers 
of a municipal utility (in one case a new municipal utility, in the 
other an existing municipal utility) that will use the transmission 
system of the retail customers' former supplier in order to access 
other suppliers.
    As we explain above, in a ``retail-turned-wholesale customer'' 
situation, such as the creation of a municipal utility system, a newly-
created entity becomes a wholesale power purchaser on behalf of the 
retail customers. It is the conduit by which retail customers, if they 
cannot obtain direct retail access, can reach power suppliers other 
than their historical local utility power supplier. Although the retail 
customers remain bundled retail customers, in that they become the 
bundled customers of the new entity, we call this a ``retail-turned-
wholesale customer'' situation because the new entity in effect 
``stands in the shoes'' of the retail customers for purposes of 
obtaining wholesale transmission access and new power supply. The same 
analogy applies to newly-annexed customers; they become ``new'' 
wholesale customers in the sense that the wholesale entity obtains 
transmission and new power supply on their behalf.
    Accordingly, we clarify that this Commission will be the primary 
forum for addressing the recovery of stranded costs if an existing 
municipal utility uses the transmission system of its annexed retail 
customers' former supplier to access new suppliers to serve the annexed 
load. As long as Commission-required transmission access (the former 
supplier's open access tariff or transmission services ordered under 
FPA section 211) is the vehicle that enables an existing municipal 
utility to obtain power supplies to serve annexed loads, we believe 
that any costs stranded as a result of this wholesale transmission 
access are properly viewed as economic costs that are jurisdictional to 
this Commission. In such a case, the bundled retail customers that are 
annexed by an existing municipal utility would, through the municipal 
utility, use the transmission system of their former supplier to obtain 
access to new supplies and thereby expose their former supplier to non-
recovery of prudently incurred costs. As in the case of new municipal 
systems that use the transmission system of their retail customers' 
former supplier, such costs would not be stranded but for the action of 
this Commission in requiring a utility to make unbundled transmission 
services available.<SUP>690
---------------------------------------------------------------------------

    \690\ SoCal Edison requests clarification that a transaction in 
which a retail customer disconnects from a utility's system and 
accesses another generation supplier by interconnecting with a 
public power entity, who in turn would interconnect with a 
neighboring jurisdictional utility, constitutes a municipalization, 
not an expansion of a service territory. Because we have decided to 
treat municipal annexations (or expansions) and new 
municipalizations similarly for purposes of stranded cost recovery 
under the Rule, SoCal Edison's request is moot to the extent that it 
envisions a scenario in which the former supplier's transmission 
system is used to access a new generation supplier. However, as 
discussed below, the Rule would not provide an opportunity to seek 
recovery of stranded costs if the municipal entity in the scenario 
described by SoCal Edison does not use the former supplier's 
transmission system.
---------------------------------------------------------------------------

    Just as we will not be the primary forum for stranded cost recovery 
for all new municipalizations, so also we will not be the primary forum 
for stranded cost recovery for all cases of municipal annexation. 
Instead, our holding is limited to those cases in which the existing 
municipal system uses Commission-mandated transmission access from the 
annexed customers' former supplying utility to obtain power from a new 
supplier. Costs that are exposed to nonrecovery when an existing 
municipal utility does not use the transmission system of the retail 
customers' former supplier to reach a new generation supplier (e.g., 
through self-generation or use of another utility's transmission 
system) do not meet the definition of ``wholesale stranded costs'' for 
which the Rule provides an opportunity for recovery. Such costs are 
outside the scope of the Rule because such costs would not be stranded 
as a direct result of Commission-required transmission access.

[[Page 12409]]

    We reject as misplaced the argument that the Commission, by failing 
to address costs that arise if a municipal utility (whether a new 
municipal utility or an existing municipal utility that annexes 
additional retail customer territory) does not use the historical 
supplying utility's transmission system, has not met its statutory 
obligation to ``set just and reasonable'' rates. The Commission in this 
rulemaking has not determined any utility's just and reasonable rates. 
Further, Order No. 888 does not by its terms bar the recovery of costs 
that do not result from the use of Commission-required transmission 
access. Utilities may, as before, seek recovery of such non-open 
access-related costs on a case-by-case basis in individual rate 
proceedings. The Commission will not prejudge those issues here.
    As we indicated in Order No. 888, we also are concerned that there 
may be circumstances in which customers and/or utilities could attempt, 
through indirect use of open access transmission, to circumvent the 
ability of any regulatory commission--either this Commission or state 
commissions--to address recovery of stranded costs.<SUP>691 We 
reiterate that we reserve the right to address such situations on a 
case-by-case basis.
---------------------------------------------------------------------------

    \691\ FERC Stats. & Regs. at 31,819; mimeo at 536-37.
---------------------------------------------------------------------------

    We share the concern expressed by Puget that a retail-turned-
wholesale customer should not be allowed to avoid any stranded cost 
obligation that it may have under Order No. 888 simply by having its 
new supplier be the entity that requests and contracts for transmission 
service from the former supplying utility. We clarify that the 
opportunity for recovery of stranded costs associated with retail-
turned-wholesale customers under Order No. 888 applies if the 
transmission system of the former supplier is used to transmit the 
newly obtained power supplies to the departing retail customer, 
regardless of whether the customer or its new supplier is the actual 
entity that requests and contracts for the unbundled transmission 
service. We have revised the definition of ``wholesale stranded cost'' 
in section 35.26(b)(1)(ii) accordingly to include the situation in 
which the retail customer subsequently becomes, either directly or 
through another wholesale transmission purchaser, an unbundled 
wholesale transmission services customer of the former supplying 
utility.
    We clarify in response to SoCal Edison's request that our decision 
to be the primary forum for recovery of stranded costs from retail-
turned-wholesale customers is not intended to prevent or to interfere 
with the authority of a state to permit any recovery from departing 
retail customers, such as by imposing an exit fee prior to creating the 
wholesale entity. As we indicated in Order No. 888, if the state has 
permitted any such recovery from a departing retail-turned-wholesale 
customer, that amount will not in fact be stranded. Accordingly, we 
will deduct that amount from the costs for which the utility will be 
allowed to seek recovery from this Commission.<SUP>692
---------------------------------------------------------------------------

    \692\ FERC Stats. & Regs. at 31,819; mimeo at 537.
---------------------------------------------------------------------------

    We clarify in response to SoCal Edison's request that the 
Commission has the discretion to defer to a state stranded cost 
calculation methodology. However, because we recognize that state 
retail access plans may present questions that need to be addressed on 
a case-by-case basis, we will consider whether to exercise that 
discretion on a case-by-case basis.
7. Recovery of Stranded Costs Caused by Retail Wheeling
    In Order No. 888, we concluded that both this Commission and the 
states have the legal authority to address stranded costs that result 
when retail customers obtain retail wheeling in order to reach a 
different generation supplier, and that utilities are entitled, from 
both a legal and a policy perspective, to an opportunity to recover all 
of their prudently incurred costs.<SUP>693 We explained that this 
Commission's authority to address retail stranded costs (i.e., stranded 
costs associated with retail wheeling customers) is based on our 
jurisdiction over the rates, terms, and conditions of unbundled retail 
transmission in interstate commerce by public utilities, and that the 
authority of state commissions to address retail stranded costs is 
based on their jurisdiction over local distribution facilities and the 
service of delivering electric energy to end users. Because it is a 
state decision to permit or to require the retail wheeling that causes 
stranded costs to occur, we decided we generally will leave it to state 
regulatory authorities to deal with any stranded costs occasioned by 
retail wheeling. The only circumstance in which we will entertain 
requests to recover stranded costs caused by retail wheeling is when 
the state regulatory authority <SUP>694 does not have authority under 
state law to address stranded costs when the retail wheeling is 
required. In such a case, we will permit a utility to seek a customer-
specific surcharge to be added to an unbundled transmission rate.
---------------------------------------------------------------------------

    \693\ FERC Stats. & Regs. at 31,824-26; mimeo at 553-58.
    \694\ ``State regulatory authority'' has the same meaning as 
provided in section 3(21) of the FPA:
    `State regulatory authority' has the same meaning as the term 
`State commission', except that in the case of an electric utility 
with respect to which the Tennessee Valley Authority has ratemaking 
authority (as defined in section 3 of the Public Utility Regulatory 
Policies Act of 1978), such term means the Tennessee Valley 
Authority.
---------------------------------------------------------------------------

    We noted that most states have a number of mechanisms for 
addressing stranded costs caused by retail wheeling. We indicated that 
rates for services using facilities used in local distribution to make 
a retail sale are state-jurisdictional, and that states will be free to 
impose stranded costs caused by retail wheeling on facilities or 
services used in local distribution. We also said that states may use 
their jurisdiction over local distribution facilities or services to 
recover so-called stranded benefits.
    We stated that we believe our approach to stranded costs associated 
with retail wheeling customers represents an appropriate balance 
between federal and state interests that ensures that the rates for 
transmission in interstate commerce by public utilities (except in a 
narrow circumstance) will not be burdened by retail costs.
    We expressed concern about the cost-shifting potential in a holding 
company or other multi-state situation, where denial of retail stranded 
cost recovery by a state regulatory authority could, through operation 
of the reserve equalization formula in a Commission-jurisdictional 
intra-system agreement, inappropriately shift the disallowed costs to 
affiliated operating companies in other states. We said that we will 
deal with such situations if they arise pursuant to public utility 
filings under section 205 or complaints under section 206. Thus, the 
need to amend a jurisdictional agreement to prevent stranded costs 
associated with retail wheeling customers from being shifted to 
customers in other states will be addressed on a case-by-case basis. We 
encouraged the affected state commissions in such situations to seek a 
mutually agreeable approach to this potential problem. If such a 
consensus solution resulted in a filing to modify a jurisdictional 
agreement, we indicated that we would accord such a proposal deference, 
particularly if other interested parties support the filing. In the 
event that the state commissions and other interested parties cannot 
reach consensus that would prevent cost shifting, we said that the 
Commission would ultimately have to resolve the

[[Page 12410]]

appropriate treatment of such stranded costs.

Rehearing Requests Opposing Any Commission Involvement in Stranded 
Costs Associated With Retail Wheeling Customers

    A number of entities dispute the Commission's statement that both 
it and the states have the legal authority to address stranded costs 
that result from retail wheeling. Central Illinois Light contends that 
the Commission's claim of dual jurisdiction is inconsistent with FPC v. 
Southern California Edison Company.<SUP>695 It says that the court in 
that case recognized that Congress meant to draw a bright line easily 
ascertained between state and federal jurisdiction, making unnecessary 
case-by-case analysis. Central Illinois Light asserts that the 
Commission has stepped over the bright line into the states' exclusive 
jurisdiction over retail rates.
---------------------------------------------------------------------------

    \695\ 376 U.S. 205, 215-16 (1964).
---------------------------------------------------------------------------

    IA Com seeks rehearing of the Commission's assertion of concurrent 
jurisdiction with state authorities over stranded costs associated with 
retail wheeling customers on the ground that it is based on the 
Commission's erroneous assertion of jurisdiction over unbundled retail 
transmission.
    IL Com says that regardless of whether the Commission's claim of 
jurisdiction over retail transmission is upheld, the Commission's 
ruling that there is joint jurisdiction over retail stranded costs is 
in error. According to IL Com, the Commission has no authority over 
such stranded costs. IL Com also disputes the Commission's 
characterization of the derivation of state authority to address such 
stranded costs. It says that state commission authority does not derive 
only from states' jurisdiction over local distribution facilities and 
the service of delivering electric energy to end users. IL Com submits 
that state commission authority to address retail stranded costs 
derives from the existence of state commission jurisdiction over the 
facilities and costs at the time of their incurrence.
    A number of entities contend that Commission jurisdiction over 
transmission facilities used in interstate commerce does not give it 
jurisdiction over stranded investment in retail generating 
assets.<SUP>696 Several argue that the fact that a retail wheeling 
customer might need transmission access from its former supplier does 
not change the character of the costs that are stranded. They maintain 
that retail stranded costs are not costs of providing unbundled 
transmission service, but are costs associated with providing what was 
formerly bundled retail service, over which the Commission has no 
jurisdiction.<SUP>697
---------------------------------------------------------------------------

    \696\ E.g., Central Illinois Light, IN Consumer Counselor, IN 
Consumers, Nucor, FL Com, WI Com, VA Com, AR Com, MO/KS Com, OH Com, 
APPA. For example, FL Com asserts that costs for facilities that are 
currently under the jurisdiction of state authorities do not become 
the Commission's jurisdiction because retail wheeling is instituted; 
in most cases, the states approved both the construction and the 
cost recovery for these facilities under bundled rate structures. FL 
Com submits that the states are in a better position to judge the 
extent and value of assets that may become stranded as a result of 
retail wheeling.
    \697\ E.g., APPA, AR Com, MO/KS Coms, OH Com.
---------------------------------------------------------------------------

    Several entities argue that it is solely the action of the state 
that allows a given utility's retail customers to seek alternative 
sources of supply; therefore, there is no nexus between the 
Commission's wholesale transmission rule and any costs that might be 
stranded by a state-established customer choice regime.<SUP>698
---------------------------------------------------------------------------

    \698\ E.g., NARUC, TAPS.
---------------------------------------------------------------------------

    A number of entities submit that the provision of FPA section 201 
that federal regulation is ``to extend only to those matters which are 
not subject to regulation by the States'' bars any attempt by the 
Commission to displace or supplant an admittedly legitimate exercise of 
state authority over retail stranded costs.<SUP>699 NASUCA submits that 
all state commissions have the authority to establish just and 
reasonable rates for the retail electric utilities in their respective 
jurisdictions.<SUP>700 It maintains that only state regulators are in a 
position to rule on the treatment of costs that were allowed in retail 
rates pursuant to state laws; the Commission has no knowledge or 
expertise regarding the specific state legal frameworks in which these 
costs were included in rates. NY Com argues that the Commission does 
not have jurisdiction to determine the rate treatment of costs devoted 
to retail service and, thus, lacks authority to allow recovery if a 
state decides not to do so.
---------------------------------------------------------------------------

    \699\ E.g., NASUCA, NY Com, WY Com, NARUC. The Consumer's 
Utility Counsel Division of the Georgia Governor's Office of 
Consumer Affairs filed comments on June 24, 1996, in support of 
NARUC's request for rehearing on the jurisdictional issues 
pertaining to the recovery of retail stranded costs. While answers 
to requests for rehearing generally are not permitted, 18 CFR 
385.213(a)(2) (1996), we will depart from our general rule because 
of the significant nature of this proceeding and will accept these 
comments.
    \700\ According to NASUCA, whether or not that authority 
includes a requirement that a utility receive 100 percent return on 
stranded costs (or something less) is a matter to be determined by 
the state courts and legislatures.
---------------------------------------------------------------------------

    VA Com argues that section 201(b)(1) of the FPA restricts the 
Commission's jurisdiction to wholesale sales. It says that a departing 
retail customer remains a retail customer, regardless of the supplier. 
VA Com concludes that no portion of the transaction is a wholesale 
sale, and that there are no wholesale costs associated with a retail 
wheeling transaction.<SUP>701
---------------------------------------------------------------------------

    \701\ See also AR Com (one retail transaction is replaced by 
another retail transaction; there is no wholesale transaction and no 
wholesale costs over which the Commission has jurisdiction).
---------------------------------------------------------------------------

    A number of entities seek rehearing of the Commission's decision 
that it will entertain stranded cost claims when the state regulatory 
authority does not have authority under state law to address stranded 
costs when the retail wheeling is required.<SUP>702 NARUC submits that 
Congress did not intend the Commission to become involved in 
adjudicating legal questions regarding the breadth of state law 
authority granted state commissions by their legislatures. NARUC 
expresses concern that the Commission would second-guess a state cost 
recovery determination and promote forum shopping. Once a balance has 
been struck at the state level concerning the terms of restructuring, 
NARUC submits that it is inconceivable that the Commission would have 
either the desire or authority to second-guess a state's legislative 
and regulatory processes.
---------------------------------------------------------------------------

    \702\ E.g., NARUC, Central Illinois Light, IN Com, American 
Forest & Paper, IN Consumer Counselor, IN Consumers, IL Com.
---------------------------------------------------------------------------

    Several entities object that the Commission effectively would 
authorize recovery of stranded costs associated with a retail wheeling 
customer if a state legislature withholds from the state regulatory 
agency the authority to approve stranded cost recovery.<SUP>703 They 
submit that just because a state has not given its regulatory 
commission the authority to impose stranded costs in the case of retail 
wheeling does not confer jurisdiction on the Commission to impose such 
charges. They contend that the state legislature should be the final 
arbiter of state policy. IL Com submits that if a state legislature 
chooses not to give its state commission the authority to act on 
stranded costs, ``that can be taken as a clear indication that the 
state's legislature most certainly does not want FERC to address 
them.'' <SUP>704 Central Illinois Light objects that the Commission has 
offered no reason why it will accept the decision

[[Page 12411]]

of the regulatory agency, but not that of the legislature.
---------------------------------------------------------------------------

    \703\ E.g., Central Illinois Light, IN Com, American Forest & 
Paper, IN Consumer Counselor, IN Consumers, IL Com. TX Com considers 
that it has the power to address stranded cost issues related to 
retail transmission service.
    \704\ IL Com at 38 (emphasis in original).
---------------------------------------------------------------------------

    AMP-Ohio and Cleveland ask the Commission to clarify that its 
deference to the determinations of the states is to the authority of 
the states as exercised through state legislative bodies (and other 
political subdivisions with legislative authority) as well as to state 
regulatory bodies. They submit that if the state legislature, or a 
local government acting in accordance with its authority, enacts retail 
wheeling legislation that expressly limits the ability of its 
regulatory body to permit recovery of stranded costs, even barring all 
such recovery, the Commission should not become involved.
    Several entities ask the Commission to clarify that Order No. 888 
does not permit utilities to apply to the Commission for recovery of 
stranded costs associated with a retail wheeling customer when a state 
regulatory authority has ``addressed'' a request for the same stranded 
costs but has not allowed 100 percent recovery.<SUP>705 ELCON gives two 
hypothetical examples to which it asks the Commission to respond: one 
where a state regulatory authority possesses full stranded cost 
recovery authority but allows only 50 percent recovery; the other where 
the state legislature provides the state regulatory authority by 
statute with the power to permit recovery of up to 50 percent of 
identified stranded costs.
---------------------------------------------------------------------------

    \705\ E.g., ELCON, NASUCA, IL Com, NY Com.
---------------------------------------------------------------------------

Commission Conclusion

    We reaffirm our conclusion that both this Commission and the states 
have the legal authority to address stranded costs that result when 
retail customers obtain retail wheeling in interstate commerce from 
public utilities in order to reach a different generation supplier, but 
that, because it is a state decision to permit or require the retail 
wheeling that causes retail stranded costs to occur, we will leave it 
to state regulatory authorities to deal with any stranded costs 
occasioned by retail wheeling. The only circumstance in which we will 
entertain requests to recover stranded costs caused by retail wheeling 
is when the state regulatory authority does not have authority under 
state law to address stranded costs when the retail wheeling is 
required.
    We will reject the requests for rehearing that oppose any 
Commission involvement in stranded costs associated with retail 
wheeling customers. We disagree with those entities that challenge our 
conclusion that both this Commission and the states have the legal 
authority to address stranded costs that result from retail wheeling 
(variously described by those entities as dual, concurrent, or joint 
jurisdiction). The Commission explained in detail in Order No. 888 the 
legal basis for concluding that this Commission and the state 
commissions each have jurisdiction over separate aspects of a retail 
wheeling transaction.<SUP>706 This Commission has jurisdiction over the 
rates, terms, and conditions of unbundled retail transmission in 
interstate commerce by public utilities. State commissions have 
jurisdiction over local distribution facilities and the service of 
delivering electric energy to end users. Based on our respective 
jurisdictions over separate aspects of the retail wheeling transaction, 
we believe either has the authority to provide the former supplying 
utility with an opportunity to recover costs stranded when the 
departing customer uses retail transmission in interstate commerce to 
reach a new supplier, but that here, unlike the retail-turned-wholesale 
scenario, the state commission should be the primary forum because 
these costs are stranded by the action of the state. We would act only 
if the primary forum is not available. We have made a policy decision 
that this Commission will step in to fill a regulatory ``gap'' that 
could result in no effective forum under which utilities would have an 
opportunity to seek recovery of prudently incurred costs.
---------------------------------------------------------------------------

    \706\ See FERC Stats. & Regs. at 31,780-85; mimeo at 427-42 and 
Appendix G.
---------------------------------------------------------------------------

    Several entities argue that the Commission does not have 
jurisdiction over stranded investment in retail generating assets, that 
use of Commission-jurisdictional transmission does not change the 
character of the costs that are stranded, that stranded costs 
associated with retail wheeling customers are not costs of providing 
unbundled transmission service, but are costs associated with providing 
what was formerly bundled retail service, and that only state 
regulators are in a position to rule on the treatment of costs that 
were allowed in retail rates pursuant to state laws. While we agree 
that stranded costs associated with retail wheeling are costs that are 
retail in character in the sense that they are in retail bundled rates 
and become stranded as a result of retail wheeling required by the 
state commission, we do not believe this precludes the Commission from 
exercising jurisdiction in the limited circumstances of the Rule.
    As an initial matter, we note that there are rarely separate retail 
and wholesale generating facilities. Retail customers and wholesale 
requirements customers get energy from the same facilities, each buying 
a ``slice of the system.'' Typically all generating assets go into both 
the retail and the wholesale rate bases for determining retail and 
wholesale rates. Rates are determined by allocating the total 
generating costs among customer classes. The parties confuse the issue 
before us to the extent they suggest that state commissions, not this 
Commission, have ``jurisdiction'' over certain ``costs.'' Neither the 
state commissions nor this Commission has exclusive jurisdiction over 
``costs.'' Each regulatory authority has jurisdiction to determine 
``rates'' for services subject to its jurisdiction and, in determining 
rates, may take into account all of the costs incurred by the utility. 
Under historical cost-of-service ratemaking, each regulatory authority, 
in exercising its respective ratemaking jurisdiction, reviews the total 
costs incurred by a utility to provide service and makes its separate 
and independent determination of what costs may be recovered through 
rates within its jurisdiction.<SUP>707 Generating costs continually 
shift between retail and wholesale rates over time.<SUP>708
---------------------------------------------------------------------------

    \707\ If a utility is regulated by both this Commission and a 
state commission, each commission, in setting cost-of-service rates 
within its jurisdiction, will separately and independently determine 
the utility's total cost of providing service (also known as the 
utility's total revenue requirement). This will be based on the 
expenses incurred in providing service and a reasonable profit on 
the utility's assets that are used to provide the service. The 
commissions may differ as to what assets are appropriately included 
in total rate base, what other costs are appropriately included in 
the total cost of service, and what rate of return should be 
permitted. Once each regulatory authority has determined the 
appropriate total revenue requirement, it then will determine what 
portion of that total revenue requirement should be borne by the 
utility's wholesale customers and what share should be borne by 
retail customers (also called cost allocation). Each commission may 
also reach different conclusions on this split as well. Thus, under 
historical cost-based ratemaking, regulatory authorities do not 
carve out so-called ``wholesale costs'' that only this Commission 
can take into account in determining rates subject to its 
jurisdiction or so-called ``retail costs'' that only a state 
commission can take into account in determining rates subject to 
state jurisdiction. Additionally, this Commission and state 
commissions have the discretion to determine whether costs are 
appropriately recovered through a transmission, generation, or 
distribution component of a rate (also called functionalization of 
costs) within their respective jurisdictions.
    \708\ We reject arguments that stranded retail generation costs 
are not a cost of providing unbundled retail transmission. While 
such costs are not a cost of operating the physical transmission 
system, nevertheless, they are an economic cost incurred as a result 
of being required to provide retail transmission.

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

[[Page 12412]]

    More importantly, both the state commission and this Commission 
have a responsibility to oversee the financial health of the utilities 
we regulate. Each has jurisdiction to make judgments about recovery of 
the costs of the assets in the utility's total rate base. Utilities are 
entitled to a regulatory forum that can adjudicate claims that they are 
or are not entitled to recovery of costs incurred regardless of the 
initial retail or wholesale ``character'' of those costs, and we 
believe we have the authority and obligation to fill a regulatory 
``gap'' that could occur.<SUP>709
---------------------------------------------------------------------------

    \709\ This is not a regulatory ``gap'' in the sense that the 
Commission would be asserting authority over matters not within its 
jurisdiction. However, the Commission would be filling a regulatory 
``gap'' to the extent that the utility normally would have the 
opportunity to seek approval from its state regulatory commission to 
recover costs in retail rates from a departing retail customer or to 
reallocate those costs to other retail customers. In circumstances 
where the utility does not have this opportunity because the state 
regulatory authority has no authority to address the issue, we may 
appropriately fill this regulatory ``gap'' to permit recovery from 
the departing customer through the retail transmission rate.
---------------------------------------------------------------------------

    In response to the argument that it is solely the action of the 
state that allows a retail customer to seek alternative sources of 
supply and, as a result, there is no nexus between the Commission's 
wholesale transmission rule and any costs that might be stranded by a 
state-established customer choice regime, we agree. Indeed, as we 
indicate in Order No. 888, we decided to leave it to state regulatory 
authorities to deal with any stranded costs occasioned by retail 
wheeling (with a limited exception) because it is a state decision to 
permit or require the retail wheeling in the first instance that causes 
retail stranded costs to occur. Our determination, as explained above, 
is to fill any regulatory gap that arises as a result of interstate 
wheeling. We believe that it is necessary for the Commission to act as 
a backstop in this limited instance to ensure that costs stranded as a 
result of retail wheeling do not go unrecovered because the state 
regulatory authority lacks the authority under state law to address 
such costs. At the same time, as we stated in Order No. 888, we believe 
that most states have a number of mechanisms for addressing stranded 
costs caused by retail wheeling. We emphasize that this Rule is not 
intended to preempt the exercise of any existing state authority with 
respect to the assessment of a stranded cost or stranded benefits 
charge on a retail customer that obtains retail wheeling.
    In response to arguments that the Commission's decision will result 
in second-guessing or interfering with a state's legislative processes 
and decisions, we believe these arguments are premature. As a general 
matter, we do not expect that our decision to be a backstop will 
interfere with legislative decisions that specifically address stranded 
cost matters and the scope of the state regulatory authority's 
authority in determining stranded costs. If states or parties to a 
retail stranded cost recovery case brought before this Commission 
believe that a Commission decision on the issue would interfere with 
state legislative decisions, they should raise their arguments, and 
support therefore, at that time.
    We clarify that Order No. 888 does not permit utilities to seek 
recovery from the Commission of stranded costs associated with retail 
wheeling customers if a state regulatory authority with authority to 
address retail wheeling stranded costs has in fact addressed such 
costs, regardless of whether the state regulatory authority has allowed 
full recovery, partial recovery, or no recovery.

Rehearing Requests Supporting Broader Jurisdiction Over Stranded Costs 
Associated With Retail Wheeling Customers

    A number of entities seek rehearing of the Commission's decision 
not to serve as a backstop for all stranded costs associated with 
retail wheeling customers. Some assert that the Commission has the 
legal authority to address independently stranded costs that arise from 
retail wheeling and that the Commission cannot lawfully abdicate or 
delegate such authority to the states.<SUP>710 Coalition for Economic 
Competition submits that the Commission correctly concluded that it has 
jurisdiction over retail transmission rates, terms and conditions and 
the authority to address retail wheeling stranded costs. Thus, it 
argues that the Commission is without the power to make a ``policy 
determination'' that results in the Commission not exercising its legal 
authority over stranded costs associated with retail wheeling 
customers. It asserts that, just as the Commission recognizes that it 
``cannot simply turn over its jurisdiction'' to the states to determine 
facilities subject to Commission jurisdiction,<SUP>711 the Commission 
cannot turn over its jurisdiction to establish stranded cost charges 
that it correctly determined it has the authority to establish. 
Coalition for Economic Competition argues that the Commission should 
adopt a stranded cost recovery policy similar to the policy the 
Commission has adopted with respect to the determination of state/
federal jurisdiction, whereby the Commission would defer to state 
stranded cost determinations so long as they are consistent with the 
Commission's policy.
---------------------------------------------------------------------------

    \710\ E.g., Utilities For Improved Transition, Coalition for 
Economic Competition.
    \711\ FERC Stats. & Regs. at 31,784; mimeo at 439.
---------------------------------------------------------------------------

    Utilities For Improved Transition argues that the Commission's 
authority over public utility rates for the transmission of electric 
power, both wholesale and retail, is plenary and exclusive. As a 
result, it submits that the Commission may not avoid responsibility for 
costs stranded by transmission of retail power.<SUP>712 Illinois Power 
contends that Congress did not authorize the Commission to reject 
jurisdictional rate filings whenever the Commission regards the state 
commissions as a more convenient or appropriate forum.
---------------------------------------------------------------------------

    \712\ Utilities For Improved Transition argues that, based on 
Consolidated Edison Company of New York, Inc., 15 FERC para. 61,174 
at 61,405 (1981) and other cases, the Commission has jurisdiction 
over the entire delivery service (rendered on both the transmission 
and local distribution facilities) as a transmission transaction. 
Utilities For Improved Transition submits that states do not have 
authority over rates on local distribution facilities used to 
complete a transmission transaction.
---------------------------------------------------------------------------

    EEI and the Coalition for Economic Competition contend that 
virtually all retail stranded costs can only occur through the vehicle 
of Commission-jurisdictional transmission in interstate commerce. They 
submit that the Commission, having recognized the clear nexus between 
FERC-jurisdictional transmission and stranded costs in the retail-
turned-wholesale context, cannot fail to recognize the same clear nexus 
in the retail wheeling context.
    Utilities For Improved Transition says that it is legally 
immaterial whether stranded costs are caused by the Commission's 
ordering the transmission or the states' doing so; the determining 
factor is who has the jurisdiction to make the rates for the service, 
not who has the jurisdiction to order the service.
    Coalition for Economic Competition and Utilities For Improved 
Transition contend that the Commission must consider stranded costs 
that arise from retail wheeling in order to satisfy its statutory 
obligation under the FPA to ``set just and reasonable'' rates. 
Coalition for Economic Competition maintains that FPA sections 201, 205 
and 206 do not give the Commission the flexibility to allow stranded 
costs in certain jurisdictional wheeling rates (e.g., wholesale 
wheeling and new municipalizations) but to exclude them from other 
jurisdictional wheeling rates (e.g., retail wheeling, municipal

[[Page 12413]]

annexation, and bypass).<SUP>713 Utilities For Improved Transition says 
that the just and reasonable standard requires the Commission to 
backstop the states to ensure that there is full stranded cost 
recovery. It objects that Order No. 888's disposition of jurisdiction 
creates a problem of cross-class discrimination (wholesale versus 
retail) and inter-class discrimination (some retail versus the 
remainder of the retail).
---------------------------------------------------------------------------

    \713\ EEI states that the Commission did not rebut EEI's 
argument that the Commission's failure to address all retail 
stranded costs was unduly discriminatory.
---------------------------------------------------------------------------

    Coalition for Economic Competition further argues that the 
Commission's failure to address all stranded costs associated with 
retail wheeling customers will result in an improper taking under the 
Constitution.<SUP>714 It also argues that the Commission is not 
permitted to disregard its findings in Order No. 888 which, according 
to Coalition for Economic Competition, ``inexorably'' lead to the 
conclusion that Commission action on ``all'' stranded costs (including 
retail wheeling, municipal annexation, and bypass stranded costs) is 
required.<SUP>715
---------------------------------------------------------------------------

    \714\ In support of its argument, Coalition for Economic 
Competition cites Federal Power Commission v. Hope Natural Gas 
Company, 320 U.S. 591, 602 (1944); Duquesne Light Company v. 
Barasch, 488 U.S 299, 307-08 (1989).
    \715\ Coalition for Economic Competition at 14.
---------------------------------------------------------------------------

    Illinois Power argues that the FPA does not authorize the 
Commission to discriminate among utilities based on the state of their 
residence, and that the Commission must allow all utilities to seek 
interstate rate recovery of just and reasonable retail stranded costs. 
Illinois Power asserts that the Rule will lead to the absurd, unduly 
discriminatory result that utilities located in states whose 
legislatures have failed to provide for stranded cost recovery will be 
better off than those located in states that provide for only limited 
stranded cost recovery. It supports use of the Commission's statutory 
authority to establish a uniform, national method for retail stranded 
cost recovery.
    Coalition for Economic Competition also contends that the 
Commission's decision to let the states deal with retail stranded costs 
is arbitrary and capricious because the Commission failed to consider 
the arguments that stranded cost opponents will make before state 
commissions, such as that a state lacks jurisdiction to impose stranded 
cost charges or that the state imposition of such charges may be 
preempted or found to be an undue burden on interstate commerce. It 
further argues that the Commission's reliance on state jurisdiction 
over the service of delivering electric energy to the end user does not 
reflect reasoned decisionmaking. It submits that the Commission has 
failed to consider that the sale of electric energy may take place 
outside of the state into which the energy is transmitted, in which 
case the state commission may have no jurisdiction over either the sale 
or the transmission of the energy and, accordingly, no authority to 
consider stranded costs.
    A number of entities ask the Commission to act on requests for 
retail stranded cost recovery when the state commission lacks authority 
or has authority to order recovery, but has declined to do so or has 
only allowed partial recovery.<SUP>716
---------------------------------------------------------------------------

    \716\ E.g., Centerior, Southern, SoCal Edison.
---------------------------------------------------------------------------

    Lastly, TX Com notes that section 35.26(d) (dealing with recovery 
of retail stranded costs) refers only to public utilities. It suggests 
that the omission of a reference to transmitting utilities appears to 
be inadvertent and should be corrected.

Commission Conclusion

    The Commission will reject the requests for rehearing of our 
decision not to assume a backstop role for all stranded costs 
associated with retail wheeling customers. We explained in Order No. 
888 that commenters that describe our action as an unlawful abdication 
or delegation of authority misconstrue the nature of our decision to 
leave stranded costs associated with retail wheeling customers (with a 
limited exception) to state regulatory authorities.<SUP>717 We have not 
``abdicated'' or ``delegated'' to state regulatory authorities our 
jurisdiction over the rates, terms, and conditions of retail 
transmission in interstate commerce; if retail transmission in 
interstate commerce by a public utility occurs, public utilities 
offering such transmission must comply with the FPA by filing proposed 
rate schedules under section 205.<SUP>718 Instead, we have made a 
policy determination that the recovery of stranded costs associated 
with retail wheeling customers--an issue over which either this 
Commission or state commissions could exercise authority by virtue of 
their jurisdiction over retail transmission in interstate commerce and 
over local distribution facilities and services, respectively--is 
primarily a matter of local or state concern for which the primary 
forum should be the state commissions. However, if the state regulatory 
authority does not have authority under state law to be the forum to 
address stranded costs when the retail wheeling is required, then we 
will entertain requests to recover such costs. As we explain above in 
response to the rehearing petitioners that oppose any Commission 
involvement in stranded costs associated with retail wheeling 
customers, we have made a policy decision that this Commission will 
step in to fill a regulatory ``gap'' that could result in no effective 
forum under which utilities would have an opportunity to seek recovery 
of prudently incurred costs.<SUP>719
---------------------------------------------------------------------------

    \717\ We also explained that the case law they cite (which they 
refer to again in their rehearing requests) to support the 
proposition that an agency is not authorized to abdicate its 
statutory responsibility or to delegate to parties and intervenors 
regulatory responsibilities is factually distinguishable and 
inapposite. See FERC Stats. & Regs. at 31,825 and note 765; mimeo at 
554-55 and note 765.
    \718\ The entities who argue that the Commission has abdicated 
or delegated its jurisdiction to the states misconstrue the 
Commission's jurisdiction to determine rates for unbundled 
transmission in interstate commerce as somehow including exclusive 
``jurisdiction'' over ``costs.'' However, as discussed above, 
neither this Commission nor the state commissions has exclusive 
``jurisdiction'' over ``costs.'' Rather, each has jurisdiction to 
determine ``rates'' for services subject to its jurisdiction. It is 
in the course of determining ``rates'' for unbundled transmission in 
interstate commerce that this Commission can take into account 
various costs incurred by a utility to provide jurisdictional 
service. A state commission can take those same costs into account 
in making its separate and independent determinations of what costs 
may be recovered through rates within its jurisdiction. See note 
707, supra, and accompanying text.
    \719\ Based on these same considerations, we reject Coalition 
for Economic Competition's request that the Commission assume a 
backstop role for all stranded costs associated with retail wheeling 
customers but defer to state stranded cost determinations so long as 
they are consistent with the Commission's policy.
---------------------------------------------------------------------------

    We disagree with Coalition for Economic Competition's argument that 
our findings in Order No. 888 ``inexorably'' lead to the conclusion 
that Commission action on ``all'' stranded costs (including retail 
wheeling and bypass stranded costs) is required, much less that the 
Commission has ignored the findings in Order No. 888. To the contrary, 
as we explain in Section IV.J.1, it is not the purpose of this Rule to 
allow utilities an opportunity to seek to recover ``all'' uneconomic 
costs that might be stranded when a customer leaves its utility 
supplier. We have fully explained our reasons for adopting an approach 
that, for purposes of stranded cost recovery from wholesale 
transmission customers, relies on the nexus between stranded costs and 
the use of transmission tariffs required by this Commission and, for 
purposes of stranded cost recovery from retail customers, recognizes 
state commission jurisdiction but fills potential regulatory gaps that 
could arise in the transition to new market structures.

[[Page 12414]]

    We disagree with those entities that contend that the Commission 
must consider retail stranded costs in order to satisfy our statutory 
obligation under the FPA to set just and reasonable rates. In 
determining just and reasonable rates for jurisdictional transmission 
service, which currently are determined on a cost basis, the Commission 
satisfies its statutory obligation under the FPA by allowing utilities 
an opportunity to recover their prudently incurred costs plus a 
reasonable rate of return. As we have explained above, this may include 
the costs of use of the physical transmission system, as well as 
economic costs incurred by the utility when it provides transmission 
service (e.g., stranded costs). However, in situations in which a state 
regulatory authority has the authority to address recovery of retail 
stranded costs, there is no regulatory ``gap,'' and there is no 
obligation for this Commission to provide a second opportunity for 
recovery.<SUP>720
---------------------------------------------------------------------------

    \720\ If the state regulatory authority is the forum before 
which to seek recovery, the utility may make whatever arguments it 
wishes regarding the justness and reasonableness of its rates, as 
well as any unconstitutional taking arguments it may have, before 
the state forum. Further, it can pursue appeals of unfavorable 
decisions through the state court system.
---------------------------------------------------------------------------

    We reject arguments that FPA sections 201, 205 and 206 do not give 
the Commission the flexibility to allow stranded costs in certain 
jurisdictional wheeling rates (wholesale wheeling and new 
municipalizations) but to exclude them from other jurisdictional 
wheeling rates (retail wheeling in interstate commerce and use of 
another utility's transmission tariff), and that this policy somehow 
makes rates discriminatory. Recovery of this type of cost through a 
transmission rate is obviously not the norm, but is necessitated by the 
need to deal with the transition costs associated with this Rule. As 
discussed in detail in the Rule, the Commission has carefully balanced 
the interests of utilities as well as customers in concluding that the 
opportunity for stranded cost recovery through transmission rates 
should be permitted in only two general circumstances: (1) in the case 
of wholesale stranded costs, where there is a direct nexus to 
Commission-required transmission access; and (2) in the case of retail 
stranded costs, where there otherwise would be a regulatory gap because 
a state regulatory authority lacks authority under state law to address 
stranded costs at the time that retail wheeling is required. We see 
nothing in the FPA that precludes us from exercising this flexibility 
and, indeed, the parties have not pointed to anything that, in our 
opinion, precludes us from exercising this discretion.
    We reject the argument that virtually all stranded costs associated 
with retail wheeling customers can occur only through the vehicle of 
Commission-jurisdictional transmission in interstate commerce, and 
therefore, that the same nexus between FERC-jurisdictional transmission 
and stranded costs that exists in the retail-turned-wholesale context 
is present in the retail wheeling context. We also disagree that it is 
legally immaterial whether stranded costs are caused by the 
Commission's ordering the transmission or the states doing so, and that 
the determining factor is who has the jurisdiction to make the rates 
for the service, not who has the jurisdiction to order the service. The 
opportunity for stranded cost recovery set forth in this Rule is based 
on the causal link between stranded costs and the availability and use 
of the Commission-required transmission tariff. It is true that in both 
the retail-turned-wholesale context and the retail wheeling context 
there is a limited nexus between stranded costs and Commission-
jurisdictional access since, in both situations, the Commission has 
jurisdiction over the rates, terms and conditions of the transmission 
service and, therefore, the authority to permit stranded cost recovery 
through the transmission rates. However, the causal nexus to FERC-
jurisdictional transmission and stranded costs in the two contexts 
(retail vs. retail-turned-wholesale) is different. In the retail 
wheeling context, there is no causal nexus between stranded costs and 
transmission that has been ordered by this Commission. In the retail-
turned-wholesale context, in contrast, the opportunity for a utility to 
seek recovery of stranded costs is grounded on the existence of a 
direct causal nexus between stranded costs and transmission that has 
been ordered by this Commission.
    We will reject the rehearing petitions that ask the Commission to 
act on requests for stranded cost recovery associated with retail 
wheeling customers not only when the state commission lacks authority, 
but also when the state commission has authority but either has 
declined to use it or has only allowed partial recovery. As explained 
above, our decision to entertain requests to recover stranded costs 
caused by retail wheeling in a limited circumstance (when the state 
regulatory authority does not have authority under state law to address 
stranded costs when the retail wheeling is required) is based on our 
determination to fill any regulatory gap that arises in association 
with interstate transmission.
    We will reject TX Com's request that the Commission clarify that 
section 35.26(d) (dealing with recovery of retail stranded costs), 
which refers only to public utilities, should also refer to 
transmitting utilities. The Commission's decision to act as a limited 
backstop in the case of stranded costs associated with retail wheeling 
customers is based on our jurisdiction under sections 205 and 206 of 
the FPA over the rates, terms, and conditions of retail transmission in 
interstate commerce. As a result, our ability to allow the recovery of 
such costs through a surcharge on a section 205 unbundled transmission 
rate is necessarily limited to public utilities.<SUP>721
---------------------------------------------------------------------------

    \721\ We note that the definition of ``retail stranded cost'' in 
section 35.26(b)(5) mistakenly refers to ``a public utility or 
transmitting utility'' (emphasis added). We will revise the 
definition to remove the reference to ``transmitting utility.''
---------------------------------------------------------------------------

Rehearing Requests Opposing Commission Treatment of Stranded Costs 
Associated With Retail Wheeling Customers in Holding Company Intra-
System Agreement Cases

    A number of entities oppose the Commission's proposal to address on 
a case-by-case basis whether jurisdictional intra-system agreements may 
need to be amended in order to prevent inappropriate cost-shifting that 
could occur if one state disallows stranded cost recovery associated 
with retail wheeling customers. IN Com objects that the problem is not 
the actions of one state or another, but rather the terms of the intra-
system agreement.
    AR Com objects that Order No. 888 is factually in error because a 
state's treatment of retail stranded costs under the Entergy System 
Agreement cannot shift costs to other jurisdictions.<SUP>722 It submits 
that whenever retail load changes, whether due to retail wheeling or 
any other factor, responsibility ratios under Entergy's reserve 
equalization schedule, MSS-1, will change and costs will shift 
irrespective of the regulator's treatment of retail stranded costs. AR 
Com says that MSS-1 reveals no changes in calculations due to retail 
treatment of stranded costs or any other retail ratemaking; only 
``excess'' capacity costs of intermediate gas- and oil-fired plant are 
``shifted'' under the Entergy System Agreement. Although the Commission 
has the authority to amend intra-system agreements when

[[Page 12415]]

wholesale cost allocations have become unjust and unreasonable, AR Com 
submits that the Commission does not have jurisdiction to reach to the 
state level and dictate what retail ratepayers should pay to 
shareholders. AR Com maintains that a FERC-jurisdictional intra-system 
agreement extends only to sales for resale (transactions among 
subsidiaries), and that if a holding company believes that an intra-
system agreement is unduly discriminatory as a result of a state's 
disallowance of costs, the holding company can propose to amend 
it.<SUP>723
---------------------------------------------------------------------------

    \722\ See also MO/KS Coms (the cost-shifting problem does not 
arise because of a particular state treatment of stranded costs; it 
arises because Entergy insists on recovering 100 percent of its 
costs even when some portion of the costs are not economical).
    \723\ AR Com also objects to the Commission's description of the 
issue as involving not only holding companies, but also other multi-
state situations. AR Com says that ``[t]he mere fact that a 
company's territory crosses state lines does not automatically mean 
that all assets serve all customers, or that all customers are 
required to bear the economic risk associated with all assets, or 
that assets that at one time were solely state-jurisdictional can 
somehow, by virtue of a company's decision to expand across state 
lines, become FERC-jurisdictional.'' AR Com at 11.
---------------------------------------------------------------------------

    AR Com argues that retail stranded costs fall to state jurisdiction 
regardless of whether the utility is a member of an interstate holding 
company. AR Com says that because the costs at issue are in retail rate 
base, any Commission influence over their recovery could occur only 
through preemption, but preemption of a state disallowance from retail 
rate base is possible only if there is a ``trapped cost.'' AR Com 
submits that a disallowance of retail rate base cost cannot result in a 
trapped cost because there is no inconsistency between two agencies 
acting within their jurisdiction; the Commission has no jurisdiction to 
act. AR Com maintains that, unlike the Grand Gulf situation, the 
Commission has not mandated any Entergy generation costs into retail 
rate base. It further says that different state decisions regarding 
recovery of retail costs are not inconsistent decisions; they represent 
each state applying its law to its facts. According to AR Com, 
decisions by states leading to less than full recovery could be deemed 
inconsistent decisions only if there were a federal guarantee of full 
cost recovery of retail costs, which there is not.
    AR Com and MO/KS Coms assert that the Commission's proposal for 
holding company situations cannot apply to future holding companies, 
where there is no history of joint planning justifying cost 
equalization, nor can it apply to future investments. They contend that 
this would require an assumption that the utility subsidiaries of a 
registered holding company have planned, and should plan, together 
rather than separately (i.e., that interaffiliate transactions are 
always more efficient than nonaffiliate transactions), and that such 
assumption would be sound only if having the transaction occur between 
affiliates is inherently more efficient than having the transaction 
occur between an affiliate and a nonaffiliate.

Commission Conclusion

    The comments raised for the most part are either premature or 
reflect a misunderstanding of the Commission's decision. Contrary to AR 
Com's argument, the Commission in Order No. 888 in no way asserted 
jurisdiction over state determinations of stranded costs associated 
with retail wheeling customers. We agree with AR Com that our 
jurisdiction extends only to sales for resale (and transmission in 
interstate commerce) and that a holding company can seek to amend an 
intra-system agreement if it believes the agreement is unduly 
discriminatory as a result of a state's disallowance of costs. However, 
a holding company also may seek to amend an agreement before any 
potential disallowances can occur, to keep cost-shifting from 
occurring. The fact is that intra-system agreements which involve 
wholesale sales among affiliate companies in different states could, 
through operation of their reserve equalization formulas, result in 
customers in one or more states having to indirectly bear stranded 
costs that are disallowed in another state, and the Commission has a 
responsibility to prevent inappropriate cost-shifting. Such 
determinations can be made only on a case-by-case basis. Again, as we 
stated in Order No. 888, we encourage affected state commissions to 
propose mutually agreeable solutions to this potential problem.
8. Evidentiary Demonstration Necessary--Reasonable Expectation Standard
    In Order No. 888, the Commission concluded that a utility seeking 
to recover stranded costs must demonstrate that it had a reasonable 
expectation of continuing to serve a customer. We stated that whether a 
utility had a reasonable expectation of continuing to serve a customer, 
and for how long, will be determined on a case-by-case basis, and will 
depend on all of the facts and circumstances. We also determined that 
the existence of a notice provision in a contract would create a 
rebuttable presumption that the utility had no reasonable expectation 
of serving the customer beyond the specified period. We said that 
whether or not a contract contains an ``evergreen'' or other automatic 
renewal provision will be a factor to be considered in determining 
whether the presumption of no reasonable expectation is rebutted in a 
particular case.<SUP>724
---------------------------------------------------------------------------

    \724\ FERC Stats. & Regs. at 31,831; mimeo at 570-72.
---------------------------------------------------------------------------

    We also said that we would apply the reasonable expectation 
standard to retail-turned-wholesale customers. We explained that, 
before the Commission will permit a utility to recover stranded costs, 
the utility must demonstrate that it incurred such costs based on a 
reasonable expectation that the retail-turned-wholesale customer would 
continue to receive bundled retail service. Whether the state law 
awards exclusive service territories and imposes a mandatory obligation 
to serve would be among the factors to be considered in determining 
whether the reasonable expectation test is met in a particular 
case.<SUP>725
---------------------------------------------------------------------------

    \725\ FERC Stats. & Regs. at 31,831; mimeo at 572. We indicated 
that the same procedures would apply to retail customers that obtain 
retail wheeling.
---------------------------------------------------------------------------

    We noted that Order No. 888 does not address who will bear the 
stranded costs caused by a departing generation customer if the 
Commission finds that the utility had no reasonable expectation of 
continuing to serve that customer. We indicated that we anticipate 
that, in such a case, a public utility will seek in subsequent 
requirements rate cases to have the costs reallocated among the 
remaining customers on its system. However, we stated that we were not 
prejudging that issue in the Rule.<SUP>726
---------------------------------------------------------------------------

    \726\ FERC Stats. & Regs. at 31,831; mimeo at 572-73.
---------------------------------------------------------------------------

Rehearing Requests Opposing or Seeking Modification of the Reasonable 
Expectation Standard

    APPA challenges the reasonable expectation standard as being too 
vague. It submits that the Commission has provided no guidance 
concerning application of the reasonable expectation standard, other 
than to state that it would decide the issue on a case-by-case basis. 
APPA objects that public utilities can exploit the uncertainty created 
by this standard, which will lead to costly and time-consuming 
litigation. IL Com supports replacing the reasonable expectation 
standard with a statutory, regulatory, contractual standard.
    Several entities contend that there is no basis to conclude that 
the reasonable expectation test could ever be met. VT DPS and Valero 
submit that, since 1973, utilities have known that a refusal to wheel 
power could subject them to antitrust liability. They say that Order 
No. 888 ignores the breadth of NRC

[[Page 12416]]

licensing conditions. LEPA similarly argues that the reasonable 
expectation standard could not be met where NRC license conditions 
required an explicit wheeling commitment and prohibited the utility 
from including in the wheeling cost any amount attributable to the loss 
of customers due to the wheeling. It objects that delaying a decision 
on stranded cost recovery in such cases holds the threat of possible 
stranded cost charges over the heads of bulk power purchasers and 
thereby chills their ability to seek competitive sellers.
    TAPS asserts that there should be an irrefutable presumption that 
no stranded costs are due from customers with pre-existing transmission 
rights, including customers who were the beneficiaries of NRC license 
conditions.<SUP>727 TAPS submits that there can be no legitimate 
``reasonable expectation'' that such customers would continue to 
purchase power if the price was higher than the market price.
---------------------------------------------------------------------------

    \727\ AMP-Ohio submits that where transmission access and 
competition have existed to varying extents for decades, there 
should be an irrebuttable presumption of no reasonable expectation 
of continued service.
---------------------------------------------------------------------------

    Occidental Chemical asks the Commission to clarify that a utility 
could have had no reasonable expectation of recovering stranded costs 
from customers who, prior to the issuance of the NOPR, had the 
opportunity to switch to an alternative electric supplier or had the 
option of self-generating, obtaining on-site third-party generation, or 
municipalizing. Occidental Chemical further argues that it defies 
commercial expectations to allow a utility to argue that if a contract 
is silent on the issue of renewal, the obligation to purchase does not 
expire with the termination of the contract. It submits that the 
Commission has not shown that it has the authority to force customers 
to extend purchase agreements against their will in violation of 
accepted commercial practice.
    A number of entities submit that the Commission erred in failing to 
treat a notice of termination provision as conclusive evidence that the 
utility had no reasonable expectation of continued service.<SUP>728 
Several object that the Commission has failed to explain why the 
presence of a notice provision does not conclusively demonstrate the 
lack of a reasonable expectation and ipso facto terminate the 
obligation of the customer to purchase the product.<SUP>729 APPA 
objects that the Commission provided no evidence that it considered 
comments supporting making the presumption conclusive and that it found 
legally sufficient reasons to reject them.
---------------------------------------------------------------------------

    \728\ E.g., APPA, American Forest & Paper, Central Montana EC, 
NRECA, TDU Systems, Oglethorpe, IMPA, VT DPS, Valero, PA Munis.
    \729\ E.g., APPA, NRECA, TDU Systems. See also VT DPS and Valero 
(by signing a contract with a termination date, the utility assumed 
the risk that the customer will elect to leave when the contract 
expires).
---------------------------------------------------------------------------

    PA Munis objects that the rebuttable presumption represents an 
unjustified departure from the Commission's traditional policy of 
enforcing the express terms of notice provisions without any inquiry 
into the reasonable expectations of the party, provided that the 
agreements were negotiated in good faith and approved by the 
Commission.<SUP>730 PA Munis contends that wholesale requirements 
customers negotiated notice provisions with the knowledge that the 
Commission would enforce the notice provisions according to their 
terms, including the specific length of the term. <SUP>731 PA Munis 
argues that it is arbitrary and capricious to provide utilities an 
opportunity to seek to amend these contracts.
---------------------------------------------------------------------------

    \730\ In support of its argument, PA Munis cites Boston Edison 
Company, 56 FPC 3414 (1976). See also American Forest & Paper.
    \731\ Citing Kentucky Utilities Company, 23 FERC para. 61,317 
(1983); Philadelphia Electric Company and Susquehanna Electric 
Company, 65 FERC para. 61,303 (1993).
---------------------------------------------------------------------------

    Several entities submit that the rebuttable presumption invites 
litigation and promotes uncertainty for customers.<SUP>732 APPA objects 
that the Commission has failed to establish the showing that it would 
require to overcome the presumption.
---------------------------------------------------------------------------

    \732\ E.g., NRECA, IMPA, PA Munis.
---------------------------------------------------------------------------

    Referring to the Commission's discussion of evergreen provisions, 
Central Montana EC argues that it is wrong to infer from the existence 
of an automatic renewal provision that the parties intended that the 
contract might run longer than its initial term. Central Montana EC 
asserts that the presence of an evergreen provision infers simply that 
the parties agreed upon a mechanism to avoid the renegotiation of a 
power supply contract if, at the conclusion of its initial term, the 
parties were satisfied with the contract. It maintains that the 
parties' obligations are defined by the term and termination provisions 
of wholesale power contracts, and that the presence of a mechanism to 
avoid contract renegotiation does not alter those termination rights.

Commission Conclusion

    We will reject the requests for rehearing of our decision to adopt 
a reasonable expectation standard to be applied on a case-by-case basis 
and to treat a notice provision in a contract as a rebuttable, not a 
conclusive, presumption of no reasonable expectation. Contrary to the 
claims of some entities, the Commission has explained the basis for its 
finding that utilities may have had an implicit obligation to serve 
their wholesale requirements customers and, therefore, that a utility 
should be given an opportunity to demonstrate that it incurred costs to 
provide service to a customer and that it had a reasonable expectation 
that it would continue to serve the customer beyond the contract 
termination date. The same factors that some petitioners contend 
establish the absence of a reasonable expectation of continued service 
may be offered as evidence to be considered in determining whether the 
reasonable expectation test is met in a particular case.
    We believe that our decision to treat a notice of termination 
provision in a contract as creating a rebuttable presumption that the 
utility had no reasonable expectation of serving the customer beyond 
the period provided for in the notice provision is a reasonable one. It 
places evidentiary significance on the fact that a contract contains a 
notice of termination provision. Moreover, while it gives the utility 
an opportunity, based on the facts and circumstances of a particular 
case, to rebut the presumption of no reasonable expectation, it firmly 
places the burden of establishing reasonable expectation on the 
utility. Although some entities support treating notice provisions as a 
conclusive presumption of no reasonable expectation, as discussed 
below, we decline to adopt such an inflexible approach. Nevertheless, 
as we indicated in Order No. 888, when a utility is seeking a contract 
amendment to permit stranded cost recovery based on expectations beyond 
the stated term of the contract, we believe that the utility has a 
heavy burden in demonstrating that the contract ought to be 
modified.<SUP>733
---------------------------------------------------------------------------

    \733\ FERC Stats. & Regs. at 31,665, 31,813-14; mimeo at 87, 
522.
---------------------------------------------------------------------------

    Contrary to the position of PA Munis, the rebuttable presumption is 
fully consistent with the Commission's past treatment of notice 
provisions. For example, the Kentucky Utilities Company case cited by 
PA Munis supports the proposition that, until a customer exercises a 
notice of

[[Page 12417]]

termination provision, the utility is under an implicit obligation to 
continue to serve and plan for the future needs of the 
customer.<SUP>734 Thus, the presence of a notice of termination 
provision in a contract (particularly one not yet exercised by the 
customer), in and of itself, may not necessarily support the conclusion 
that the utility could never prove that it reasonably expected to 
continue serving the customer beyond the notice period.<SUP>735
---------------------------------------------------------------------------

    \734\ See Kentucky Utilities Company, 23 FERC at 61,679-80 
(``Once it receives an effective notice of cancellation, Kentucky 
can stop planning for the future needs of that customer. . . . To be 
effective a notice of cancellation must contain a specification of 
the source of supply, the date on which the source of supply will be 
available, and an affidavit from the supplier that it will supply 
the customer on the date the contract ends.'').
    \735\ See Potomac Electric Power Company, 43 FERC para. 61,189 
(1988) (suspending a notice of termination for five months due to 
questions about the impact of the proposed cancellation on service 
reliability).
---------------------------------------------------------------------------

    In response to APPA's objection that the Commission has failed to 
establish the showing that it would require to overcome the 
presumption, we note that the Commission cannot establish such a 
showing upfront because whether there is sufficient evidence to rebut 
the presumption of no reasonable expectation will depend on the facts 
of each case.
    We appreciate the concerns expressed by some entities that the 
rebuttable presumption may increase the customer's uncertainty by 
inviting litigation. We have carefully weighed the pros and cons of 
treating a notice provision as a rebuttable presumption of no 
reasonable expectation versus the pros and cons of treating it as a 
conclusive presumption of no reasonable expectation. It is true, as 
some entities assert, that the rebuttable presumption approach presents 
the potential for litigation between the parties as to whether, in a 
particular case, the utility can rebut the presumption. The alternative 
would be to treat all contracts with notice of termination provisions 
as conclusive evidence that the utility could have had no reasonable 
expectation that it would continue to serve the customer beyond the 
specified notice period. While the latter approach presumably would 
reduce the number of cases in which the issue of a utility's reasonable 
expectation would have to be litigated, it would do so only by 
prohibiting a utility from ever demonstrating that, notwithstanding the 
existence of a notice provision, based on the facts of a particular 
case, the utility reasonably expected to continue serving the customer. 
While we do not prejudge the likelihood of a utility being able to 
rebut the presumption in a particular case, we believe that it would 
not be in the public interest for the Commission to absolutely preclude 
a utility from being able to make such a showing. On this basis, we 
conclude that treating a notice provision as a rebuttable, rather than 
a conclusive, presumption that the utility did not have a reasonable 
expectation of continuing service to the customer is, on balance, the 
fairer and more equitable approach.
    Central Montana EC asserts that it is wrong to infer from the 
existence of an automatic renewal provision that the parties intended 
that the contract might run longer than its initial term. However, our 
statement in Order No. 888 that the existence of an automatic renewal 
provision will be a factor to be considered in determining whether the 
presumption of no reasonable expectation is rebutted in a particular 
case makes no such inference. Whether the utility can rebut the 
presumption will depend on the facts of each case.

Rehearing Requests Supporting Modification of Evidentiary Standard for 
Retail Customers

    Several entities ask the Commission to consider adopting a 
rebuttable presumption that utilities had a reasonable expectation of 
continuing to serve any retail load for which they had a public utility 
obligation to serve. They submit that the burden should be on the 
former bundled retail customer to show that the utility's service 
obligation was not binding and that the utility's expectation of 
continuing service was unfounded.<SUP>736 Florida Power Corp and 
Utilities For Improved Transition suggest that the only exception to 
such a rebuttable presumption should be for retail customers that gave 
notice of termination before the effective date of the Rule. EEI 
expresses concern that the issue may be wrongly decided on the 
existence (or lack) of an exclusive franchise. It states that while 
many states do award franchises delineating exclusive service 
territories, some do not, even though long-established service 
arrangements are in place. Puget submits that because there is a duty 
to serve all retail customers, Order No. 888 should provide for 
stranded cost recovery from all departing retail customers without 
application of a reasonable expectation test.
---------------------------------------------------------------------------

    \736\ E.g., EEI, Oklahoma G&E, Southern, Florida Power Corp, 
Utilities For Improved Transition.
---------------------------------------------------------------------------

    NY Com, on the other hand, opposes application of the reasonable 
expectation standard to stranded costs associated with retail-turned-
wholesale customers. It argues that the reasonable expectation test 
would ignore prudence, customer impact, financial viability and a 
series of criteria traditionally analyzed by state regulatory agencies 
in determining rate treatment of costs incurred with the intention of 
providing service.

Commission Conclusion

    We will deny the requests for rehearing of the Commission's 
decision to apply the reasonable expectation standard to retail-turned-
wholesale and retail wheeling customers on a case-by-case basis without 
adopting a rebuttable presumption that utilities had a reasonable 
expectation of continuing to serve any retail load for which they had a 
public utility obligation to serve. When a utility seeks to recover 
stranded costs from former bundled retail customers, we think it is 
appropriate that the utility bear the burden of proving reasonable 
expectation (instead of requiring the customer to bear the burden of 
disproving the utility's reasonable expectation). Placing the burden on 
the utility is consistent with the requirement of sections 205 and 206 
of the FPA that a public utility demonstrate the justness and 
reasonableness of its proposed rates. The same factors that are offered 
as support for the establishment of a rebuttable presumption of a 
reasonable expectation (such as the utility's obligation to serve all 
retail customers) may be offered by the utility as evidence to be 
considered in determining whether the reasonable expectation test is 
met in a particular case.
    We also will deny NY Com's request that the Commission not apply 
the reasonable expectation standard to retail-turned-wholesale 
customers. We believe it is appropriate to require the same evidentiary 
demonstration for recovery of stranded costs from a retail-turned-
wholesale customer as that required in the case of a wholesale 
requirements customer. Moreover, as discussed in Section IV.J.7 above, 
the reasonable expectation standard contemplates evidence as to what a 
utility might reasonably expect to recover under state law, and we will 
give great weight to a state's view of what might be recoverable.
9. Calculation of Recoverable Stranded Costs
    In Order No. 888, the Commission considered various proposals 
regarding how stranded costs should be calculated and who should pay. 
With respect to the calculation of stranded costs, the Commission 
rejected as overly complicated and costly an asset-by-asset

[[Page 12418]]

approach to determine the amount of stranded costs assigned to a 
departing customer. Instead, the Commission determined that the 
revenues lost approach was the fairest and most efficient way to make 
this determination during the transition to a competitive wholesale 
bulk power market. The Commission adopted the following revenues lost 
formula for calculating the stranded cost for each departing customer: 
SCO-(RSE--CMVE) x L. The Commission provided a precise definition for 
each component of the formula,<SUP>737 and made the application of the 
formula, and collection of the resulting stranded costs, subject to a 
number of conditions.<SUP>738
---------------------------------------------------------------------------

    \737\ Briefly, SCO refers to the departing customer's stranded 
cost obligation, which is determined by taking the average annual 
revenues that the customer would have paid had it remained a 
customer of the utility (RSE), and subtracting from it the 
competitive market value of the power (on an average annual basis) 
no longer taken by the departing customer (CMVE). The difference 
represents the average annual stranded cost, which must be 
multiplied by ``L'' (L represents the period over which the utility 
reasonably could have expected to serve the departing customer 
beyond the contract termination, but for the open access required 
under Order No. 888) to produce the departing customer's total SCO.
    \738\ FERC Stats. & Regs. at 31,839-40; mimeo at 595-99.
---------------------------------------------------------------------------

RSE Issues

    Numerous petitioners oppose the use of present revenues in the 
stranded cost formula.<SUP>739 TDU Systems argues that the revenues 
lost approach is arbitrary and capricious because its effect exceeds 
its purpose. Specifically, TDU Systems contends that the revenues lost 
approach can permit overrecovery because it provides recovery of any 
difference between pre-Order No. 888 cost-plus rates and post-Order No. 
888 competitive rates, regardless of the cause of the difference. TDU 
Systems cites enhanced utilization and technological improvements as 
two examples of pre-and post-Order No. 888 rate differences that are 
not competition related, but for which recovery would be provided. TDU 
Systems states that instead of using present revenues, RSE should be 
calculated based on the most current, reliable estimate of future 
revenues.
---------------------------------------------------------------------------

    \739\ E.g., TDU Systems, APPA, Central Vermont, ELCON.
---------------------------------------------------------------------------

    Multiple Intervenors argues that the revenues lost method assumes 
that a utility's costs of operating its plants are per se reasonable, 
yet the New York utilities' current rates include levels of O&M, 
especially wages and benefits, expenses that may reflect inefficiencies 
and thus are not stranded costs for which a utility's shareholders 
should be compensated. Similarly, other petitioners oppose as backward-
looking the use of present revenues for what should be a forward-
looking remedy, consistent with the other elements in the 
formula.<SUP>740 TDU Systems argues that the use of past revenues is 
inappropriate in a falling cost environment, and notes that new 
capacity costs are less than the existing capacity costs embedded in a 
utility's rate base.
---------------------------------------------------------------------------

    \740\ E.g., TDU Systems, NRECA, Central Montana EC, SoCal 
Edison.
---------------------------------------------------------------------------

    NYSEG states that the Commission should permit a utility to 
reconcile initial stranded cost charges to actual stranded costs on a 
periodic basis to account for changes in sales, energy purchases from 
NUGs, and changes in market price. NYSEG supports development of 
stranded cost charges based on three-year estimates. Under this 
approach, a customer would pay locked-in charges for a series of three-
year periods. At the end of each period, the stranded cost estimate 
would be revised for the next three-year period. This process would 
continue until all stranded costs are recovered.<SUP>741 Other 
petitioners support the use of a projected revenue stream or a true-up 
mechanism.<SUP>742 These petitioners argue that a true-up mechanism is 
necessary to protect all parties against the inevitable risk of 
inaccurate forecasts.
---------------------------------------------------------------------------

    \741\ See also Coalition for Economic Competition at 47.
    \742\ E.g., Central Vermont, Texaco, Carolina P&L.
---------------------------------------------------------------------------

    ELCON argues that calculating RSE based upon customer usage over 
the past three years results in an artificially high stranded cost 
because it fails to take into account that the utility would have had 
to reduce its prices in the future in response to competition. ELCON 
states that wholesale customers have a reasonable expectation that 
utility costs will be lower in the future, and thus that the annual 
revenues contributed by a customer who remains with the utility would 
be lower than RSE. ELCON further contends that the revenues lost 
formula should not guarantee the profits the utility was allowed to 
receive prior to the issuance of Order No. 888 because such revenues 
included a risk factor (e.g., plant operating risk, or risk of customer 
insolvency) that is absent under the direct assignment method of 
allocating stranded costs. ELCON cites Town of Norwood v. FERC <SUP>743 
as support for its position that the RSE should be reduced to reflect 
the decreased risk associated with the direct assignment approach.
---------------------------------------------------------------------------

    \743\ 80 F.3d 526 (D.C. Cir. 1996) (Town of Norwood).
---------------------------------------------------------------------------

    TDU Systems and NRECA also argue that the Commission should 
eliminate from RSE the risk component of the return on equity contained 
in present rates. They argue for this adjustment because the Commission 
is eliminating the risk associated with non-recovery of plant costs by 
providing full recovery of stranded costs. NRECA further contends that 
if the Commission keeps the equity return in the calculation of 
stranded costs, it should permit a consumer-owned system to include an 
imputed equity component in its RSE if it needs to recover stranded 
costs.
    APPA argues that the use of present revenues fails to reflect 
future cost reductions expected from accumulated depreciation, load 
growth, and declining capital costs. APPA further opposes the use of 
present revenues because present revenues are the direct product of the 
monopoly power that the utility exercised over transmission. APPA 
states that RSE should be calculated based upon the price of wholesale 
power in a competitive market.
    CCEM argues that only fixed costs should be eligible for recovery, 
and that this amount should exclude any return on investment. CCEM 
would exclude variable costs from the calculation of stranded costs 
because allowing recovery of variable charges would encourage the 
continued operation of facilities that are conceded to be uneconomic. 
CCEM further contends that the Commission should provide less than full 
recovery of stranded costs so that the utility has some incentive to 
mitigate them.
    Central Vermont states that where the contract does not commit the 
customer to a set amount of service, the utility's reasonable 
expectation of the amount of continuing service will not necessarily be 
reflected in the revenues of the three previous years. Central Vermont 
urges the Commission to allow utilities the option of showing that 
their actual reasonable expectation of continued service differs from 
historical experience. Central Vermont maintains that any other 
approach would be less than reasonable, and, in fact, would be 
arbitrary and capricious.
    Numerous petitioners <SUP>744 would retain the use of present 
revenues as the RSE; however, they support a limited exception that 
would permit a utility to seek recovery of certain future cost 
increases (primarily nuclear decommissioning costs, back-loaded PURPA 
contract costs, and other deferred costs) if those costs are not in 
rates now or are in rates but are being under-recovered at present. 
These

[[Page 12419]]

petitioners argue that the majority of these costs were incurred as a 
result of various regulatory mandates, with the reasonable expectation 
of future recovery in rates. As a part of their proposal, Utilities For 
Improved Transition and EEI (and others) support offsetting such cost 
increases with any decreases in other costs reflected in present 
revenues. Utilities For Improved Transition maintains that nuclear 
decommissioning costs, in particular, should be revisited as they 
become better defined. Similarly, Nuclear Energy Institute and others 
request that the Commission allow a utility, on a case-by-case basis, 
to propose its own recovery mechanism, as nuclear decommissioning costs 
are significantly different from other future cost increases.
---------------------------------------------------------------------------

    \744\ E.g., EEI, Utilities For Improved Transition, VEPCO, 
Coalition for Economic Competition.
---------------------------------------------------------------------------

    Lastly, TDU Systems and NRECA object to the manner by which the 
formula deducts average transmission-related revenues (which would be 
unbundled in the utility's new open access tariff) in the development 
of RSE. TDU Systems and NRECA contend that the transmission credit, 
because it is based on the revenues that would be generated under a 
utility's new wholesale tariff, would not reflect that the cost of 
transmission has been declining.

Commission Conclusion

    In Order No. 888, the Commission stated that the use of ``present'' 
annual revenues as the basis for the stranded cost calculation has 
numerous advantages over other approaches advocated. The Commission 
noted that the use of present revenues (1) eliminates disputes over 
estimates of future revenues, providing certainty to the calculation; 
and (2) eliminates the need for a detailed listing and litigation of 
includable costs, relying instead on the presumption that present rates 
include all just and reasonable costs of providing service. The 
Commission further noted that the rates that produce present revenues 
have been approved by regulators, which strongly suggests that the 
costs included in them are prudent, legitimate and verifiable.
    The Commission continues to believe that the use of present 
revenues as the basis for the stranded cost calculation is superior to 
other proposed methods. Arguments that the use of present revenues 
either over-or under-recovers ``true'' costs are not persuasive. Either 
the customer or the utility may file for a change in rates before the 
existing contract ends if it believes the existing rate is 
inappropriate.
    In response to petitioners requesting an RSE based on estimates of 
future revenues for the reasonable expectation period (L), we continue 
to believe that an approach based on estimates of future revenue 
streams would engender countless disputes over the RSE component in the 
formula with little, if any, added accuracy. These would in effect be 
rate cases that attempt to litigate not what costs were during a test 
year based on audited accounting data, but what costs will be, based on 
speculation about future fuel costs, employment levels, capital costs, 
and so on. In contrast, we believe that the use of present revenues 
will produce fair results and minimize litigation of RSE. This is 
appropriate for a transition period cost recovery charge that needs to 
be settled quickly for market participants to make business decisions 
about future wholesale sales and purchases. Our approach minimizes 
transaction costs and provides greater certainty with respect to the 
RSE term in the formula.
    Some have argued that a method that periodically adjusts the 
departing customer's stranded cost obligation in the future to reflect 
actual future increases or decreases in a utility's future cost-based 
rates would produce more accurate results. However, this ``true-up'' 
approach has several difficulties. First, it assumes that the utility 
will have wholesale cost-based rates in the future. Many utilities 
already sell in the wholesale market at market-based rates, and this 
trend is accelerating. Having a series of ongoing rate cases solely for 
the purpose of trueing-up a stranded cost calculation would be 
cumbersome and costly. It would eliminate much of the regulatory cost 
savings that result from market-based rates. Further, even if ``cost-
based'' rates were on file in the future, many such future wholesale 
rates, as in the past, are likely to result from settlements among the 
parties. Such settlements are agreements on prices that do not 
necessarily spell out the cost components of the final agreed-upon 
rate.
    These difficulties aside, the true-up approach would introduce a 
great deal of ongoing uncertainty about the departing customer's 
stranded cost obligation. This uncertainty would add unnecessary risk 
for both the customer and the utility as they consider alternative 
purchase or sales transactions. Customers would have no way of knowing 
what their ultimate stranded cost charge would be, and therefore would 
be unable to evaluate definitively whether changing suppliers would be 
beneficial. Under a true-up approach, the eventual sum of the 
customer's SCO and replacement power cost could be more or less than 
the amount it would have paid had it simply stayed with its host 
supplier. This possibility could discourage many customers from taking 
advantage of the open access provided by Order No. 888. We believe that 
any potential accuracy benefit of a true-up approach is greatly 
outweighed by the cost, uncertainty, delay, and litigation such an 
approach would cause.
    In summary, we believe that the use of present revenues as the 
basis for calculating stranded cost appropriately balances precision 
and efficiency <SUP>745 for what is fundamentally a transition period 
policy.
---------------------------------------------------------------------------

    \745\ The use of present revenues is reasonably workable from an 
administrative standpoint.
---------------------------------------------------------------------------

    In response to the other arguments raised, the Commission makes the 
following findings. We disagree with ELCON that the use of present 
revenues will result in an artificially high stranded cost because it 
fails to account for the fact that a utility would have to lower its 
prices to respond to new competition. ELCON's argument is circular in 
that much of the new competition to which it refers results from our 
issuance of Order No. 888. ELCON's approach would undo the goal of 
providing recovery of stranded costs by eliminating the very difference 
that the formula is intended to determine. <SUP>746 ELCON's argument is 
rejected accordingly.
---------------------------------------------------------------------------

    \746\ Our rationale here is equally applicable to APPA's 
argument that RSE should be based upon the price of wholesale power 
in a competitive market.
---------------------------------------------------------------------------

    In addition, ELCON's reliance on Town of Norwood (for the 
proposition that RSE should be reduced to reflect the reduced operating 
risk and reduced risk of customer insolvency associated with direct 
assignment of stranded costs) is misplaced. In Town of Norwood, the 
Commission was faced with a request for recovery of plant costs. The 
utility made a cost-effective proposal to shut down its single asset, a 
small nuclear reactor. In that case, the Commission disallowed full 
return on investment in part because the unit was no longer operating 
and the utility had no operating risk.
    Elimination of the rate of return is inappropriate because, unlike 
Town of Norwood, the departing customer's service is not tied to any 
particular unit; rather, service is considered to be provided by the 
entire system. Contrary to ELCON's assertion, operating risk is not 
reduced because the utility must continue to operate its generating 
facilities (by reselling the capacity) if it is to recover all its 
costs. Accordingly,

[[Page 12420]]

there is not a reduced operating risk as argued by ELCON.
    With respect to ELCON's customer insolvency argument, this risk is 
also present under the direct assignment approach. Because Order No. 
888 permits a customer to pay its stranded cost obligation over a 
number of years, during this period the customer could become 
insolvent, thereby leaving the utility with uncollected stranded 
costs.<SUP>747
---------------------------------------------------------------------------

    \747\ In addition, Order No. 888 provides recovery of only the 
difference between the average annual revenues that the customer 
would have paid had it remained a customer (RSE) and the estimated 
competitive market value (CMVE) of the released power (i.e., the 
stranded cost). However, while the formula contemplates that the 
utility can sell the released power at the estimated competitive 
market value, the actual market value may be lower, increasing the 
risk that the utility will not be able to recover its stranded 
costs.
---------------------------------------------------------------------------

    Also, unlike Town of Norwood, the utility is presently collecting 
rates that compensate for traditional utility risks, but do not include 
the risk of open access. Further, eliminating the rate of return would 
engender considerable complication, speculation and expense as the 
Commission would have to determine an appropriate rate of return that 
included some risks (e.g., customer bankruptcy) but not others (e.g., 
211 request or use of the open access tariff). Thus, eliminating the 
rate of return (or a portion thereof) is inappropriate.
    Accordingly, ELCON's arguments that the revenue stream should be 
reduced to reflect lower risk associated with direct assignment is 
rejected. Instead, we continue to believe that the transmission 
provider is entitled to recover all the costs, including return on 
equity, that it incurred based on a reasonable expectation of having to 
serve the departing customer. All these costs would have been 
recoverable absent the action taken in Order No. 888.<SUP>748
---------------------------------------------------------------------------

    \748\ In Order No. 888, the Commission rejected arguments that 
return-related revenues be excluded from the revenue stream. The 
Commission found that such exclusion would effectively require 
shareholders to absorb stranded costs, which is contrary to the 
Commission's finding that a utility is entitled to an opportunity to 
fully recover legitimate, prudent and verifiable stranded costs. In 
this order, we reaffirm our earlier finding.
---------------------------------------------------------------------------

    The Commission also rejects NRECA's proposal to include an imputed 
equity component in the RSE when calculating stranded costs for a 
consumer-owned system. Simply put, if a cost is not stranded, or if a 
cost is not really a cost, recovery should not be granted.
    The Commission rejects APPA's contention that it is inappropriate 
to use present revenues as the RSE because those revenues are the 
direct product of the monopoly power that the utility exercised over 
transmission. The Commission believes that the use of present revenues 
is one of the strengths of the formula in that the rates that produce 
present revenues have been approved by regulators as just and 
reasonable, which strongly suggests that the costs included in them 
have been shown to be prudent, legitimate and verifiable.
    In response to CCEM's argument that only fixed costs should be 
eligible for recovery (because the inclusion of variable costs in the 
RSE will encourage the continued operation of facilities that are 
conceded to be uneconomic), we agree. The Commission notes that 
condition 1, ``Cap on SCO'' <SUP>749 limits the recovery of stranded 
costs to fixed costs. Accordingly, the formula, as designed, addresses 
CCEM's concern.
---------------------------------------------------------------------------

    \749\ FERC Stats. & Regs. at 31,840; mimeo at 597.
---------------------------------------------------------------------------

    We note that Central Vermont supports its opposition to the use of 
present revenues differently from other petitioners, who argue (in 
effect) that the price component of RSE is flawed.<SUP>750 Central 
Vermont, on the other hand, is concerned that the quantity component of 
present revenues may not reflect the quantity that would have been 
taken during L. It states that the Commission should permit the utility 
to show that it had a reasonable expectation of continued customer 
service that is not based on the customer's previous three years of 
power consumption. The Commission does not believe that this is 
appropriate. Central Vermont's approach would introduce forecasting 
controversy, litigation cost, and uncertainty which are similar to the 
disputes about cost discussed above. For example, a utility might argue 
that the customer was expected to consume more than it has in the last 
three years, based presumably on such factors as expected economic 
development, changing demographics, appliance saturation rates, and 
even changes in climate. Conversely, the departing customer might argue 
that it would have increased electricity conservation efforts, used 
more natural gas, relied more on self-generation, and so on, if open 
access had not been made available by Order No. 888. The Commission has 
stated above why it favors the use of present revenues, for both price 
and quantity combined, and these reasons apply regardless of whether 
the argument is directed toward the price or quantity component of 
present revenues.
---------------------------------------------------------------------------

    \750\ Present revenues depend, of course, on both price and 
quantity. Most petitioners who dispute the use of present revenues 
argue, in some fashion or another, that present revenues are 
inappropriate because the costs included in present revenues may not 
equate to the costs incurred by the utility during L. These 
petitioners are arguing about price.
---------------------------------------------------------------------------

    Finally, TDU Systems' and NRECA's argument regarding the 
transmission revenue credit component of RSE is made on the same basis 
as their argument that the revenue stream should be calculated on a 
forward-looking basis. For the reasons discussed above, we reject this 
argument also.
    Therefore, after consideration of the arguments on rehearing, and 
reconsideration of our policy rationale supporting the use of present 
revenues, we continue to support the use of present revenues, without 
true-ups or adders, as the basis for the stranded cost formula. We find 
that the use of present revenues fairly and efficiently balances the 
competing interests of the affected parties.

CMVE Issues

    Petitioners raised a number of CMVE related issues. We take them up 
in the following two categories.

Present Value Issues

    EEI agrees with the Commission that stranded costs should be 
calculated on a present value basis. EEI states that with respect to 
RSE, the formula appears to be stated on a present value basis, 
although it believes that the language could be strengthened to read: 
``the present value of average annual revenues from the departing 
customer over the three years prior * * * '' (new text emphasized).
    However, EEI maintains that the rule fails to define CMVE clearly 
on a present value basis. Therefore, EEI suggests that the Commission 
clarify the definition as follows: ``Option 1--the utility's estimate 
of the net present value of the average annual revenues * * * or Option 
2--the net present value of the average annual cost to the customer of 
replacement capacity and associated energy * * * '' (new text 
underlined). EEI states that this clarification could also be applied 
to the ``Cap on SCO,'' to put it on a par with the other definitions in 
terms of the time value component.
    TDU Systems and NRECA also express concerns regarding the 
calculation of SCO on a present value basis. Specifically, they state 
that the formula contains no component, factor, or other mechanism to 
indicate how such present value is to be determined. They also state 
that no discount rate is specified, and that the calculation should be 
synchronized with the customer's chosen payment option. Central Vermont 
maintains that the Commission should make it clear that a utility is 
entitled to recovery of both

[[Page 12421]]

stranded costs and the time value of those costs from the date on which 
they were experienced through the date of their recovery.

Commission Conclusion

    We believe that EEI misinterprets our intent with the three-year 
average annual revenues for RSE. EEI is proposing to increase the 
revenues of three years ago to current dollars, the revenues of two 
years ago to current dollars (and so on) before finding the three-year 
average. The Commission clarifies that our use of the term ``present 
value'' does not require such an adjustment. If the utility thought its 
rates on file did not adequately reflect rising costs, it should have 
filed for a rate increase. If it did file for and receive a rate 
increase, the formula does not use a three-year average, but rather 
revenue based on the new rate.<SUP>751 It would be inappropriate to 
adjust the three years of revenue used to calculate RSE to a current 
dollar value if these rates have been in effect for three years without 
change. It is assumed that all costs, including inflationary and 
deflationary changes in the underlying costs, have been recovered. We 
do not have any time lag between the provision of service and the 
recovery of the costs of providing that service. Accordingly, EEI's 
proposed present value adjustment is neither necessary nor appropriate.
---------------------------------------------------------------------------

    \751\ Condition 2 requires use of the most recent twelve months 
of revenue if there has been a rate change. See FERC Stats. & Regs. 
at 31,840; mimeo at 597.
---------------------------------------------------------------------------

    With respect to EEI's concern that CMVE is not determined on a 
present value basis, we clarify that it should be calculated on a 
present value basis. Both the revenues that would have been collected 
if the customer had remained on the system and the revenues the utility 
expects to collect by selling the power must be stated on a present 
value basis so that the difference, RSE-CMVE, is at present 
value.<SUP>752 The ``Cap on SCO'' must also be stated on a present 
value basis.
---------------------------------------------------------------------------

    \752\ If RSE and CMVE are calculated on a present value basis, 
and the difference between the two is multiplied by L, the result 
constitutes the customer's SCO. This present value is the amount to 
be paid under the lump-sum payment option. If the customer chooses 
another payment option, additional time-value calculations would be 
required to match the customer's stranded cost obligation with a 
series of payments made over time.
---------------------------------------------------------------------------

    In response to TDU Systems, NRECA and Central Vermont, we clarify 
that a utility is entitled to recovery of stranded costs and the time-
value of the revenues that would have been recovered.<SUP>753 However, 
we decline to specify the discount rate or the number of periods to be 
used in the calculation. Although establishing a uniform discount rate 
would serve to minimize disputes over the calculation, we prefer to 
give the parties some flexibility on the use of a discount rate. 
Similarly, we do not prescribe the number of periods to be used in the 
present value calculation as this also should be determined on a case-
by-case basis due to differences in ``L'' and billing payment cycles 
for each departing customer.
---------------------------------------------------------------------------

    \753\ The utility is entitled to recover no more than the 
present value of the revenue stream (less the competitive market 
value) it would have received had the customer remained on its 
system.
---------------------------------------------------------------------------

CMVE Option 2 Issues

    In Order No. 888, the Commission allows the departing customer to 
set CMVE equal to the average annual revenues it would pay to its 
alternative supplier. This option is referred to as CMVE Option 2.
    SoCal Edison and Central Vermont argue that CMVE Option 2 should be 
eliminated because it will be administratively difficult to monitor and 
enforce. In their view, Option 2 will allow customers the opportunity 
to ``game'' the system, which will increase the utility's and the 
Commission's administrative costs and place the utility at risk for 
less than full recovery of stranded costs. In addition, SoCal Edison 
maintains that it will be difficult to reflect in the calculation of 
stranded costs any non-price benefits a customer may receive under the 
contract. SoCal Edison further maintains that there is a possibility 
that additional bargains may have been struck outside of the agreement 
between the new supplier and the departing customer. These bargains may 
have the effect of increasing the price of the alternative power, but 
the terms of the bargains would not be known to the utility to use in 
adjusting CMVE. As a result, the customer's contract price may not 
accurately reflect the utility's CMVE, resulting in an inaccurate 
estimate of stranded cost responsibility.
    EEI has requested that the Commission clarify that the conditions 
placed on CMVE Option 2 were intended to prevent the customer from 
unfairly avoiding its full stranded cost obligation (i.e., prevent 
gaming of the stranded cost calculation). EEI also states that the 
Commission should give the utility an opportunity to challenge the 
validity of the replacement contract's price, terms and conditions on a 
case-by-case basis or give the utility the right of first refusal to 
provide power to the customer under the replacement contract's price, 
terms and conditions. Carolina P&L requests that the Commission require 
the departing customer to make a compliance filing containing 
information regarding the replacement contract. Centerior maintains 
that in order to guard against the customer overpaying for replacement 
capacity (thereby lowering its SCO), the Commission should use the 
revenues received by the host utility in the resale of the power to 
determine the CMVE.
    NRECA and TDU Systems maintain that the formula fails to address 
how the CMVE component will be adjusted when the customer's contractual 
commitment for replacement capacity is for a period shorter than L.

Commission Conclusion

    The comments filed in response to our Open Access NOPR maintained 
overwhelmingly that determining accurately the competitive market value 
of the released capacity and energy is a difficult and subjective task. 
Therefore, we did not prescribe a CMVE by formula as we did for RSE. 
Instead, we provide options for determining it. Our requirement for the 
utility to estimate it is CMVE Option 1. However, the customer may 
contend that the utility will underestimate CMVE under this option so 
as to increase the customer's stranded cost obligation. In response to 
these concerns, the Commission adopted CMVE Option 2 because ``[t]he 
customer will test the market and choose the best deal available. 
Hence, the price the customer pays its alternative supplier is arguably 
a more accurate measure of the competitive market value of the capacity 
and associated energy not taken from the host utility.'' <SUP>754 The 
Commission also believes that, because of the potential for disputes 
over the CMVE component of the formula, many utilities and departing 
customers would appreciate CMVE Option 2 because it would provide them 
with a simple and reliable method for determining the CMVE.
---------------------------------------------------------------------------

    \754\ FERC Stats. & Regs. at 31,842; mimeo at 604.
---------------------------------------------------------------------------

    However, the Commission recognized the potential for gaming on the 
part of the customer. To address this potential, the Commission placed 
certain conditions on the use of Option 2. One of these conditions is 
that the departing customer must demonstrate that the replacement 
service is equivalent to that from the current supplier. This provides 
the utility with the ability to investigate whether the new service is 
essentially the same, in terms of contract duration, terms and 
conditions, as that which it currently provides the customer. Any 
unresolvable disputes over the value of

[[Page 12422]]

non-price benefits contained in the customer's replacement contract, 
which is SoCal Edison's concern, can be developed during a stranded 
cost hearing, and the Commission will decide the disputed issues based 
on the record provided. SoCal Edison's concern with additional bargains 
outside the contract, which increase the contract price and lower the 
customer's SCO, is properly addressed through the discovery process. 
The utility could ask for a copy of agreements between the new supplier 
and the departing customer, and the customer would be obligated to 
provide the requested information.
    Although we recognize that there may be difficulties in assuring 
the ``equivalence'' of the customer's replacement contract, we believe 
that CMVE Option 2 creates an incentive for the utility to estimate 
CMVE as accurately as possible (in Option 1), and provides a quick and 
simple alternative to protracted litigation of the utility's estimate 
of CMVE. Accordingly, SoCal Edison's and Central Vermont's request for 
elimination of CMVE Option 2 is rejected. Also, because a utility is 
permitted to undertake discovery regarding the terms and conditions of 
the replacement contract, and any contracts or considerations 
associated with the replacement contract, we do not believe that it is 
necessary to give the utility the right of first refusal to supply the 
departing customer under the replacement contract's price, terms and 
conditions. EEI's ``gaming'' concerns are best addressed through the 
discovery process in a stranded cost hearing.
    Furthermore, we will not require the departing customer to make a 
compliance filing containing information about its replacement 
contract, as the utility can obtain this information through discovery 
if it is needed and relevant, without automatically burdening the 
Commission with additional filings or requiring the customer to 
disclose confidential and irrelevant information. A customer must file 
replacement contract information only if it chooses to assert that the 
replacement contract price is relevant to the determination of 
CMVE.<SUP>755
---------------------------------------------------------------------------

    \755\ We note that in a section 206 proceeding initiated by a 
customer, Order No. 888 requires that estimates of stranded cost 
liability shall include the information necessary to allow the 
utility to understand the basis of the estimate. (Mimeo at 610 
referencing Implementation Procedure (2)). The implementation 
requirements in Implementation Procedure (2) apply not only to a 
utility making a stranded cost estimate, but also to a customer 
filing under section 206. Therefore, in case Order No. 888 is 
unclear, we clarify that a customer filing under section 206 and 
choosing CMVE Option 2 must include a copy of its replacement 
contract and any other information necessary to determine the 
equivalence of its replacement contract.
---------------------------------------------------------------------------

    In response to NRECA and TDU Systems, the Commission reiterates 
that a customer cannot avail itself of CMVE Option 2 if its replacement 
contract is for a period shorter than L. This restriction is necessary 
to ensure equivalence of service.

Marketing/Brokering Option Issues

    In Order No. 888, the Commission allows the departing customer to 
market or broker the capacity that it would strand as a result of its 
decision to purchase power from an alternative supplier. This option is 
intended to protect a departing customer from a low utility estimate of 
CMVE, which would result in a higher stranded cost charge to the 
customer.
    ELCON maintains that the option to broker the released power in 
response to a ``low balling'' of the CMVE by a utility places an unfair 
burden on the customer by requiring it to engage in brokering.
    SoCal Edison and NIMO argue that a customer choosing the marketing 
option should pay the utility's estimate of the market value of energy, 
rather than the average system energy costs for the energy it 
purchases. SoCal Edison and NIMO argue that the use of average system 
energy costs is inconsistent with the use of estimated market value 
used to calculate the customer's stranded cost responsibility and will 
result in an under-recovery of stranded costs. Florida Power Corp is 
also concerned that the payment provisions of the marketing option 
could result in under-recovery of stranded costs. Specifically, Florida 
Power Corp states that permitting customers to purchase the associated 
energy at average system variable costs is appropriate if the stranded 
capacity marketed by the customer is slice-of-system and if the energy 
used is at the same load factor as the average load factor of the 
utility's remaining requirements customers. If these conditions are not 
met, Florida Power Corp states that under-recovery or over-recovery of 
stranded costs could occur. To prevent this, Florida Power Corp would 
require the customer to reimburse the utility for the marketed energy 
at the utility's actual hourly average energy costs for the hours in 
which the energy is resold.
    Occidental Chemical requests guidance as to when a stranded cost is 
``legitimate'' and how the utility will develop an estimate of the 
capacity to be released. Occidental Chemical also requests 
clarification regarding the obligations of a departing customer to the 
replacement buyer and whether the departing customer can resell the 
capacity under terms and conditions different from those under which it 
bought it. Similarly, CCEM requests that the Commission clarify that 
there can be no conditions attached to the former customer's use of the 
capacity, except for conditions pertaining to safety and reliability. 
CCEM also contends that the 60-day limit for finding a buyer under the 
brokering option is too short and should be eliminated. CCEM states 
that if the customer pays for the capacity in the stranded cost charge, 
it should have flexibility in disposing of it.

Commission Conclusion

    The Commission disagrees with ELCON that the brokering option 
places an unfair burden on the departing customer. The Commission 
believes that the marketing/brokering option is another effective 
incentive for a utility to make a good faith estimate of CMVE. 
Furthermore, we note that the marketing/brokering option is just that: 
an option. A customer is not required to exercise the marketing/
brokering option, just as it is not required to exercise CMVE Option 2. 
Rather, the marketing/brokering option is available to a customer who 
believes it can reduce its stranded cost obligation through marketing 
or brokering the released power.<SUP>756
---------------------------------------------------------------------------

    \756\ If the customer decides not to exercise either CMVE Option 
2 or the marketing/brokering option, the customer still would be 
permitted to challenge the reasonableness of the utility's CMVE 
estimate (under CMVE Option 1) as well as the reasonableness of the 
other aspects of the utility's stranded cost estimate.
---------------------------------------------------------------------------

    In response to SoCal Edison, NIMO and Florida Power Corp, the 
Commission believes that permitting a customer to purchase the 
associated energy under the marketing option at average system variable 
costs is appropriate in most instances for at least two reasons. First, 
the capacity being marketed in all or almost all cases would not be 
associated with a single asset or subset of assets. Instead, a customer 
who chooses to exercise this option is purchasing a ``slice of the 
system,'' i.e., a fraction of the production of all assets. 
Accordingly, our requirement that the customer purchase the associated 
energy at average system variable costs is consistent with the notion 
that it is purchasing a slice-of-the-system. Furthermore, we believe 
that the customer should have the opportunity to purchase the 
associated energy at the price it currently pays, and for most 
customers that price is based on average

[[Page 12423]]

system costs. It is not appropriate to require market value pricing of 
associated energy when the customer's present payments are based on 
average system variable costs. For SoCal Edison and NIMO, we further 
clarify that, when the departing customer markets the released power at 
a market-based rate and pays average system variable cost for the 
energy component of the price, the difference between the market price 
of the power and the average system variable cost determines the market 
value of the released capacity. When we refer to ``purchasing energy at 
average system variable cost,'' we refer to compensation for the 
variable cost component of the sale (mostly fuel cost); we are not 
referring to the total price of the power sale, which would include a 
fixed cost recovery component.
    We agree with the argument of Florida Power Corp. The Commission 
recognizes that there may be instances where the departing customer 
does not purchase energy at average system variable costs. We also 
recognize that the entity to which the departing customer sells the 
released capacity may have a usage pattern that differs significantly 
from that of the departing customer. In this circumstance, the utility 
should be paid actual hourly average energy costs for the hours in 
which the energy is resold by the departing customer. Parties should 
address this issue in their marketing agreement.
    In addition, we clarify that the departing customer's capacity 
charge is the utility's CMVE minus average system variable costs as 
contained in its estimate of RSE.<SUP>757 Hence, the capacity charge is 
the fixed cost that the utility could recover if it sold the power at 
market value. This approach assumes that the customer choosing the 
marketing option is buying a slice of the system and buys the energy 
associated with the released capacity on the same basis as under its 
contract with the utility.
---------------------------------------------------------------------------

    \757\ For estimation purposes the utility should still provide 
its CMVE on a market value basis for both capacity (fixed) and 
energy (variable) so that customers can better understand the basis 
for the utility's estimate.
---------------------------------------------------------------------------

    In response to Occidental Chemical, a stranded cost is legitimate 
if it meets the criteria established in the Rule. With respect to the 
obligations of a departing customer to a replacement customer, such 
obligations will be governed in part by the individual contracts 
between the parties. However, with respect to Occidental Chemical's 
question as to whether the departing customer can resell the capacity 
under terms and conditions different from those under which it bought 
the capacity, the Commission finds that, at a minimum, the customer is 
entitled to resell the capacity and energy under the terms and 
conditions governing its purchase from the utility. However, customers 
would not be precluded from negotiating different terms and conditions 
with the utility.
    In response to CCEM's concerns, the Commission will not prohibit a 
utility from attaching conditions to the former customer's use of the 
system. There may be circumstances (which we have not contemplated) 
where certain conditions may be necessary, and we do not wish to 
foreclose such instances at this time. However, we caution utilities 
against using this to restrict the customer's use of this option. We 
reiterate our finding in Order No. 888 that the utility should allow 
the customer to market/broker the released capacity under terms and 
conditions comparable to a utility resale of the capacity to a third 
party.
    The Commission disagrees with CCEM that the 60-day period for 
finding a buyer under the brokering option is too short and should be 
eliminated. The 60-day period protects both customers and utilities in 
the event that an acceptable buyer for the power cannot be found. It 
protects the utility from being stuck with the released capacity for an 
extended period, during which time it can receive only minimal 
compensation for it.<SUP>758 Similarly, the 60-day limit protects the 
customer by reverting back to the formula if its brokering attempt is 
unsuccessful. CCEM's argument that the customer who pays for the 
capacity in the stranded cost charge should have flexibility in 
disposing of it ignores the fact that under the brokering option (as 
opposed to the marketing option), the customer does not take title to 
the released capacity. For these reasons, the Commission continues to 
believe that a time limit is necessary, and that 60 days is adequate to 
meet the dual goals described above.
---------------------------------------------------------------------------

    \758\ This is so because, throughout the period that the 
customer is trying to find a buyer, the utility can sell the 
released capacity and energy only in the short-term market, most 
likely at a lower price than it could receive in a longer-term 
market. The utility is limited to the short-term market because the 
capacity must be available when the customer finds a buyer.
---------------------------------------------------------------------------

Length of Reasonable Expectation Issues

    American Forest & Paper faults the Commission for failing to limit 
the period of reasonable expectation to a discrete period, such as 
three to five years. TDU Systems contends that the threat of stranded 
costs extends well beyond a mere transition period, and therefore, is 
inconsistent with the Commission's statement that stranded costs are a 
transition issue. TDU Systems maintains that the period of reasonable 
expectation should be defined as the shorter of either the term of the 
terminating contract or the utility's planning horizon as of July 11, 
1994. IL Com states that absent a statutory, regulatory or contractual 
obligation to incur costs or provide service, the length of a utility's 
expectation to serve a customer beyond its contract expiration should 
be zero. However, IL Com states that if a statutory or regulatory 
obligation to serve can be demonstrated by a public utility on a case-
by-case basis, extra-contractual recovery may be appropriate but should 
not exceed three years. IL Com proposes a formula for L that 
incorporates a three-year cap.

Commission Conclusion

    We reiterate that our stranded cost procedure applies to wholesale 
contracts only if they are entered into on or before July 11, 1994 (and 
do not contain exit fees or other stranded cost provisions), so that as 
these contracts end this stranded cost recovery procedure will cease to 
apply. This fact alone shows that the policy is a transition issue and 
not a permanent policy for wholesale requirements contracts. Further, 
it should be remembered that a utility must demonstrate that it had a 
reasonable expectation of continued service for a time certain (L) 
before any stranded cost is recognized to exist or recovery permitted. 
This is not an insignificant demonstration. Moreover, although we 
decline to establish an outside limit for L, it is likely that the 
longer the period claimed by the utility, the harder it will be for the 
utility to demonstrate a reasonable expectation. In any event, to 
provide recovery of the full stranded cost, it is necessary that the 
reasonable expectation period not be limited to an arbitrary number, 
such as three to five years, as suggested by American Forest & Paper.
    Regarding the time it takes to complete the transition to a market 
unaffected by stranded cost considerations, the Commission 
distinguishes the reasonable expectation period for determining the 
amount of stranded costs attributable to a departing customer from the 
period over which the customer pays for stranded costs. For example, a 
utility may have incurred a cost under the expectation that the 
customer would remain for another seven years (L). However, the 
customer could pay that amount

[[Page 12424]]

immediately, over three years, over seven years, or over a longer 
period. The period of reasonable expectation, L, is unrelated to the 
repayment period. If all customers were to choose the lump-sum payment 
option, the transition period to a market completely unaffected by 
stranded cost recovery would be short.
    In response to TDU Systems, we note that its proposal to define the 
period of reasonable expectation as the shorter of either the term of 
the terminating contract or the utility's planning horizon as of July 
11, 1994 is not foreclosed by our Rule. When faced with a claim for 
stranded costs, TDU Systems may argue that either of these limit the 
reasonable expectation period in that instance. However, it would be 
inappropriate to limit generically the period of reasonable expectation 
as suggested because the limitation may not fit all circumstances. We 
reiterate that whether a utility had a reasonable expectation of 
continued service, and for how long, will be determined on a case-by-
case basis, and will depend on the facts and circumstances of each 
individual case.
    With respect to IL Com's argument that absent a statutory, 
regulatory or contractual obligation to incur costs, the length of a 
utility's expectation to serve a customer beyond its contract 
expiration should be zero, the Commission agrees that such obligations 
are likely to be the principal reasons for a reasonable expectation in 
most cases, but we would not preclude a utility from introducing other 
relevant evidence. If a utility can demonstrate that costs were 
incurred to serve a customer, based on a reasonable expectation of 
continued service, and if that customer uses the open access provided 
by Order No. 888 to reach an alternative supplier, leaving the utility 
with unrecovered costs, the utility should be allowed to make its case 
for recovery of those costs based on whatever evidence it chooses to 
offer.

Implementation Issues

    SoCal Edison is concerned that, under the framework established in 
Order No. 888, a customer could request numerous estimates of stranded 
costs based on different alternative supply scenarios and departure 
dates, to which the utility would have to respond in a 30-day period. 
SoCal Edison states that the Commission should reasonably limit the 
number and types of requests. SoCal Edison maintains that if the number 
and type of a customer's requests are unduly burdensome or unreasonable 
in the utility's view, the utility should be permitted to refuse the 
requests. Under SoCal Edison's approach, the customer would have the 
right to petition the Commission to demand that such studies be 
undertaken.
    SoCal Edison also argues that the Commission should allow a utility 
to assess a reasonable charge to cover administrative costs associated 
with developing the studies required to produce estimates of stranded 
cost responsibility.
    TDU Systems states that the 30-day period allowed for a customer to 
respond to a utility's notice of alleged stranded costs is too little 
time to perform an adequate analysis. In addition, TDU Systems and 
NRECA maintain that a customer should not be bound by its estimate of 
stranded cost obligation as filed in a petition for declaratory order 
or a section 205 or 206 proceeding. They contend that certain elements 
of the formula depend heavily on data in the public utility's 
possession, and that the Rule, as written, will encourage the customer 
to present a low-end estimate of stranded cost liability. TDU Systems 
and NRECA maintain that the Commission should instead require the 
customer to state its binding estimate at the close of the discovery 
period when it presumably would be in possession of the data necessary 
to make a realistic estimate of the stranded cost floor.
    PSE&G argues that a utility should be able to begin recovering 
stranded costs right away, subject to refund pending the outcome of the 
proceeding, to eliminate any incentive a customer would have to delay 
proceedings so as to delay payment of stranded costs.

Commission Conclusion

    Regarding SoCal Edison's concern about numerous requests for 
estimates of stranded costs, we do not believe that the number of 
requests will rise to the level of ``unduly burdensome'' or 
``unreasonable'' in most instances. However, if this problem occurs, a 
utility can petition the Commission for relief, and we will consider 
each petition on a case-by-case basis.
    The Commission does not agree with SoCal Edison that a utility 
should be permitted a special charge to cover the cost associated with 
providing a stranded cost estimate. Such costs are likely to be de 
minimis. Given that Order No. 888 provides an opportunity for full 
recovery of stranded costs, we do not believe it is appropriate for a 
utility to charge a customer an additional fee for asking whether it 
can expect a stranded cost claim.
    The Commission also disagrees with TDU Systems that the 30-day 
customer response period is too short. No utility has argued on 
rehearing that the 30-day utility response to a request for an estimate 
is too short, and only TDU Systems argues that the 30-day customer 
response to the utility's estimate is too short. The 30-day period is 
intended to speed the negotiation process, with the goal of settling 
stranded costs disputes without Commission involvement. Order No. 888 
requires a utility to provide an estimate of stranded cost 
responsibility within 30 days of the customer's request for an 
estimate. We do not believe it is unreasonable to require the customer 
to respond in like time. Accordingly, we will not modify the 30-day 
response requirement.
    Furthermore, the Commission is unpersuaded by TDU Systems' and 
NRECA's argument that a customer should be bound by its estimate of 
stranded cost obligation only after the close of the discovery period. 
Order No. 888 requires the utility to provide detailed support for its 
stranded cost estimates, and this information should be adequate to 
allow the customer to develop its own estimate of any stranded cost 
obligation.
    In response to PSE&G, we clarify that recovery of stranded cost 
claims filed under section 205, 206, or 211/212 will be governed by 
these sections and the Commission's promulgating regulations thereto.

Net Benefit Issues

    EGA and IMPA argue that the revenues lost approach does not capture 
the net utility benefits that result from open access. EGA states that 
no stranded costs should be imposed on any one ``lost'' customer if the 
utility is a ``net winner,'' that is, where the benefits from the new 
competitive regime outweigh the utility's stranded costs. EGA states 
that the formula is unclear as to how the revenues lost approach will 
take into account the following three potentially beneficial effects of 
competition: (1) an expanded customer base as a result of enhanced 
transmission access; (2) reductions in the cost of purchased power, 
which is resold by a utility; and (3) a utility's ability to obtain 
higher than cost of service rates for electricity. Freedom Energy 
argues that the potential future benefit should be factored into the 
revenues lost calculation.
    IMPA maintains that a mechanism should be provided for recovery of 
the benefits of open access, particularly if a utility does not seek 
stranded cost recovery. IMPA states that it is economically inefficient 
for consumers of generation and transmission services to pay stranded 
costs to those suppliers that have higher than average cost generation, 
while the benefits from

[[Page 12425]]

increases in asset value are not shared with the consumers or used to 
pay for other utilities' stranded costs. IMPA further contends that if 
the customer's departure as a power customer frees up the generating 
capacity for remarketing through the use of the transmission system, 
section 212 of the FPA, as modified by the Energy Policy Act, supports 
recognition of such benefits in the price paid by the customer for its 
continued usage. Finally, IMPA maintains that if a transmission 
provider seeks stranded cost recovery for an asset that appears ``high 
cost'' due to its relative youth, the asset's future lower cost as an 
older unit must also be included in the calculation; otherwise the 
departing customer will be denied the long-term average benefit of the 
generating asset.
    Multiple Intervenors contend that there should be consistent 
treatment of all assets that deviate from fair market value. For 
example, if a utility is allowed to recover the difference between the 
book value of an asset and its lower market value, then that amount 
should be offset by the appreciated value of any assets that have a 
market value higher than book value. Similarly, ELCON and Freedom 
Energy are concerned that the revenues lost approach may overcompensate 
a utility for stranded costs because it fails to account for the fact 
that uneconomic assets may be offset by the increased economic value of 
other assets in a deregulated environment.<SUP>759 Freedom Energy 
states that losses may occur in the short run, but in the long run the 
utility may be better off.
---------------------------------------------------------------------------

    \759\ Freedom Energy and ELCON reference a study conducted under 
the aegis of the Massachusetts Attorney General to support their 
position that the future benefits of deregulating sales of energy 
and capacity will produce a net gain for utilities that is often 
sufficient to offset the full amount of any potential stranded 
costs.
---------------------------------------------------------------------------

Commission Conclusion

    The Commission believes that the suggestion by EGA and others that 
a long-run comprehensive analysis be undertaken every time a customer 
departs, in order to determine whether the utility would eventually be 
a net winner, is unworkable. Identifying the competitive market value 
for power during the reasonable expectation period (L) is hard enough; 
EGA would have us also find the market value of the power for an 
indefinite time after the expectation period ends. Further, attempts to 
define which benefits are the result of Order No. 888 would, at the 
very least, be unwieldy and highly subjective. The Commission's 
approach, on the other hand, is far less subjective and more likely to 
produce a reasonable result.
    With respect to the specific ``potentially'' beneficial effects of 
competition during the period L, which EGA states should be used to 
offset stranded costs, the Commission finds these benefits to be 
questionable at best. However, if these potential benefits occur, the 
Rule's stranded cost approach accommodates them. For example, our 
clarification (infra) that the formula addresses load growth responds 
to EGA's first concern that the formula should take into account the 
expanded customer base that results from open access. EGA's second 
concern, i.e., that the formula should reflect reductions in the cost 
of purchased power, is misplaced. If, in a future market-based pricing 
world, a utility can purchase power at a lower cost, it must either 
pass this lower cost through to customers in its cost-based rates or 
sell power at similarly low market-based rates to other customers. In 
either case, except for possible timing considerations, it is unable to 
profit by buying low and selling high. If a utility has such a 
hypothetical benefit before the customer departs, the customer may file 
a section 206 complaint prior to the termination of the existing 
contract, so that the resulting rates, reflecting the reduction in the 
cost of purchased power, could be used to calculate RSE. Lastly, if a 
utility can sell at market-based rates that are higher than cost-based 
rates (other than in the speculative long run), it would not qualify to 
recover stranded costs.
    In addition, ELCON's and Freedom Energy's concern that utilities 
may be overcompensated under the revenues lost approach is based on a 
study that assumes a fully deregulated environment. There is no basis 
for this assumption over the next several years. Furthermore, it is 
highly speculative whether a particular utility will necessarily be 
better off in future markets as the study predicts. This is especially 
so because Freedom Energy's argument that future benefits should be 
used to offset stranded costs appears to assume a short reasonable 
expectation period, L. We do not find merit in Freedom Energy's 
suggestion that events beyond the reasonable expectation period should 
be factored into the stranded cost calculation.
    The Commission also believes that IMPA's benefit reallocation 
proposal is inappropriate and unworkable. It would require a utility 
not requesting stranded cost recovery to share with its wholesale 
customers any future benefits that would accrue to it as a result of 
Order No. 888. Customers have purchased power from utilities at cost-
based rates that have been found to be just and reasonable by this 
Commission. Such purchases in no way convey an ownership interest in 
the facilities used to provide service. The rationale for stranded cost 
recovery, i.e., payment for investments made to serve a customer under 
the utility's reasonable expectation of continuing to serve, cannot be 
converted into what would be in effect an ownership interest with the 
right to receive a share of profits from future sales. Moreover, IMPA's 
argument assumes that utilities whose assets have a book value less 
than market value will be able to charge market-based rates for their 
capacity. This assumption is unrealistic for many utilities, and 
therefore cannot be relied upon as basis for a generic policy. However, 
even if all utilities could charge market-based rates, economic 
efficiency would argue strongly against such utility payments to 
departing customers. Specifically, there would be little or no 
incentive for an efficient, low cost utility to seek the best deal in 
the power market if the profits must be credited back to its former 
customers, or other utilities' customers, as IMPA suggests. Therefore, 
while IMPA's symmetry argument (i.e., customers must pay stranded costs 
so equity requires utilities to pay customers any benefits that result 
from open access) may have surface appeal, it would serve to undo the 
goal of Order No. 888--that is, to promote competition and economic 
efficiency in bulk power markets. The Commission considered carefully 
the issue of symmetry in Order No. 888 and provided the appropriate 
utility-customer symmetry: a utility is entitled to make the case that 
it expected the customer to remain a customer longer than the term of 
the contract and the customer is entitled to make the case that the 
term of an existing contract should be shortened.
    We also reject IMPA's argument that section 212 of the FPA requires 
recognition in transmission rates of any generation benefits that 
accrue to a utility as a result of Order No. 888. Section 212 requires 
the Commission to consider all costs incurred by the transmission 
provider in providing the service, ``including taking into account any 
benefits to the transmission system of providing the transmission 
service.'' <SUP>760 We do not interpret this to refer to the resale of 
a utility's generation freed-up as a result of Order No. 888.
---------------------------------------------------------------------------

    \760\ 16 U.S.C. Sec. 824(a).
---------------------------------------------------------------------------

    IMPA's argument that if a transmission provider seeks stranded cost 
recovery for an asset that appears

[[Page 12426]]

``high cost'' due to its relative youth, the asset's projected future 
lower (depreciated) cost as an older unit must also be included in the 
calculation, improperly focusses on an individual asset. As we 
explained above, the revenues lost approach is not an asset-by-asset 
approach, but an approach that looks at a utility's current rates which 
are based on all the utility's assets, including typically a mix of 
facilities of various ages.
    Lastly, the revenues lost approach automatically includes an offset 
of the type described by Multiple Intervenors, ELCON and Freedom 
Energy. The revenue stream is based on present rates, which are based 
on the net book value of all of the underlying assets used to provide 
the service. If present rates include some assets that have a market 
value that exceeds net book value (for example, plants that are almost 
fully depreciated), the formula automatically captures the described 
offset because the revenue stream is based on the lower book value of 
the utility's assets rather than their higher market value.

Miscellaneous Formula Issues

Rehearing Requests

    American Forest & Paper argues that the definition of wholesale 
stranded costs in section 35.26(b)(1) is overly inclusive; rather than 
using a gross measure of stranded costs, it believes the regulations 
should adopt a net measure that accounts for a utility redeploying its 
assets in a competitive market at market price. American Forest & Paper 
also maintains that the formula fails to reward efficient utilities or 
those that already have borne the pain of restructuring. On the 
contrary, it argues that the Commission's definition artificially and 
unjustifiably improves the competitive position of the inefficient 
utilities. American Forest & Paper further contends that the formula 
fails to allocate the risk of non-mitigation to utilities, the entities 
that are in the best position to mitigate such costs, but rather places 
the risk on customers by requiring customers to challenge the utility's 
CMVE.

Commission Conclusion

    In response to American Forest & Paper, we note that the definition 
of wholesale stranded cost in section 35.26(b)(1) should not be looked 
at in isolation. Although that definition does not specifically mention 
the subtraction of the competitive market value of the released power 
from RSE, the revenues lost formula, which is set forth in section 
35.26(c)(2)(iii), does. The formula explicitly provides that a 
customer's stranded cost obligation is to be calculated by subtracting 
the estimated competitive market value (of the released power) from the 
revenue stream estimate.
    In response to the argument that the formula fails to reward the 
efficient utility that has already borne the pain of restructuring, we 
note that our intention in providing stranded cost recovery was not to 
review or reward utility business decisions that preceded this Rule. 
Our decision was, at bottom, based on equity for a utility that chooses 
to make a case to regulators for recovery of costs stranded by 
transmission access. Furthermore, we disagree that the definition of 
stranded costs artificially and unjustifiably improves the competitive 
position of an inefficient utility. Instead, the Commission believes 
that to deny stranded cost recovery would violate the pre-existing 
regulatory compact and would unjustifiably place certain utilities with 
stranded costs at a financial disadvantage.
    With respect to American Forest & Paper's concern about mitigation 
risk, the Commission requires the utility to mitigate, or reduce, its 
stranded cost by reselling the released capacity at a price as high as 
the market allows. In addition, Order No. 888 contains several other 
incentives (e.g., the marketing/brokering option) to protect the 
departing customer from paying an excessive stranded cost charge. These 
incentives serve to mitigate stranded costs. Regarding the customer's 
``requirement'' to challenge the utility's CMVE, we view this as the 
customer's right to challenge the utility's stranded cost estimate, 
which is like its right to challenge a cost item in any rate case.

Rehearing Requests

    NRECA and TDU Systems maintain that the formula fails to account 
for any savings or reductions in fuel costs attributable to a 
customer's departure. NRECA and TDU Systems contend that the utility's 
fuel costs will decrease equivalent to the incremental fuel costs 
associated with the energy not taken. They maintain that if the 
customer's associated revenues are based on average fuel cost energy 
charges, stranded costs should be offset by the reduction in average 
system fuel costs directly related to the incremental fuel costs 
savings. They argue that any stranded cost recovery mechanism should 
properly reflect such offsetting savings.

Commission Conclusion

    The Commission disagrees with NRECA and TDU Systems that the 
formula fails to account for any savings or reductions in fuel costs 
attributable to a departing customer. The formula automatically 
accounts for fuel costs by assuming that the utility will be reselling 
the same capacity and energy to another buyer, presumably at a lower 
price. The lower price can be viewed as contributing less to capital 
cost and purchased power cost recovery, but containing the same fuel 
cost component. Under this approach, any decrease in fuel cost caused 
by no longer serving the departing customer is offset by the increased 
fuel cost of serving the new customer. Hence, there is no fuel costs 
savings to reflect.

Rehearing Requests--Divestiture

    CCEM continues to support divestiture of generating assets as a 
precondition to a utility's authority to recover stranded costs. CCEM 
maintains that divestiture is the only way to obtain an accurate 
determination of CMVE on a net asset basis.

Commission Conclusion

    The Commission disagrees that divestiture is the only way to obtain 
an accurate measure of CMVE and we continue to believe that mandatory 
asset divestiture does not need to be a requirement for stranded cost 
recovery. However, the Rule (Section IV.J.10) states that we are 
willing to consider case-specific proposals for dealing with stranded 
costs in the context of any voluntary restructuring proceeding 
instituted by an individual utility.

Rehearing Requests--Load Growth and Excess Capacity

    TDU Systems and NRECA argue that the formula fails to take into 
account the effect of load growth on the recovering utility's revenues. 
They maintain that if the recovering utility is able to sell the 
released capacity to new or existing customers, the rationale for 
stranded cost recovery would be eliminated. Similarly, Arkansas Cities 
argues that the formula is an imperfect indicator of a utility's 
stranded costs because it does not explicitly take into account the 
role played by the utility's having (or not having) excess capacity. PA 
Munis maintains that as a prerequisite to stranded cost recovery, a 
utility should be required to prove that the customer's use of open 
access transmission actually resulted (or could result) in excess 
capacity on its system. <SUP>761
---------------------------------------------------------------------------

    \761\ See also Wisconsin Municipals.

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

[[Page 12427]]

Commission Conclusion

    We clarify that our stranded cost policy does take into account the 
effects of load growth and excess capacity. The formula is used to 
calculate the value of stranded costs only if the Commission determines 
that the utility has proved it has legitimate, prudent, and verifiable 
stranded costs. For example, it must pass our reasonable expectation 
test before the formula applies. However, costs may be stranded only if 
they are not fully recovered from another customer; that is, the 
released capacity may be either left unsold or resold at a price below 
full embedded cost.
    The resale may be either to a new third-party customer or to 
remaining native load. If the released capacity is resold to a third-
party customer at full embedded cost-based rates, then no costs would 
be stranded and the formula would not have to be used. Released 
capacity would also be considered ``resold'' if its cost is 
subsequently (and without delay) included in the rate base of the 
utility's retail and wholesale native load. It may be included if it is 
needed, in the judgment of the appropriate state or federal regulatory 
body, for native load growth plus reliability reserve. In this case the 
cost is not stranded if it is fully recovered in the cost-based rates 
paid by native load. If the full embedded cost rate is paid by the new 
purchaser for the capacity released by the departing customer, the 
parties may argue either that there is no stranded cost or that the 
formula produces a stranded cost obligation of zero because CMVE equals 
the embedded-cost rate that the utility charges its wholesale and 
retail native load customers; hence RSE equals CMVE.
    In response to Arkansas Cities, if the released capacity was 
included in the Commission-approved cost-based rates paid by the 
departing customer, we presume that such capacity is not ``excess'' 
capacity. The departing customer's rate (which produces annual 
revenues, RSE) for the released capacity includes capacity that 
regulators have approved as needed to meet the needs of requirements 
customers, including capacity needed for reliability reserve. The only 
excess capacity issue is whether the released capacity becomes 
``excess'' because of the customer's departure, that is, whether the 
departure strands costs because the utility cannot find a buyer for the 
capacity. If the released capacity is ``excess'' capacity that is 
excluded from subsequent native load rates because it is not needed for 
native load, its cost may be eligible for stranded cost recovery under 
the formula. Thus, contrary to the arguments made by TDU Systems, 
NRECA, Arkansas Cities, Pa Munis and others, the revenues lost formula 
does take load growth and excess capacity into account appropriately in 
determining the departing customer's stranded cost obligation. For this 
reason, we reject the arguments made by commenters that the formula is 
flawed.

Rehearing Requests--Tax Treatment of Nuclear Decommissioning Costs

    EEI and Nuclear Energy Institute request clarification that the 
Commission did not intend Order No. 888 to change the IRS's tax 
treatment of nuclear decommissioning costs. To be tax deductible, 
nuclear decommissioning costs must be part of a utility's regulated 
cost of service. EEI and Nuclear Energy Institute seek clarification 
that costs included in a utility's stranded cost calculation continue 
to be considered by the Commission as included in the utility's cost of 
service.

Commission Conclusion

    The requested clarification is granted. We clarify that costs 
included in a utility's stranded cost calculation continue to be 
considered by the Commission as included in the utility's cost of 
service.

Rehearing Requests--Application of Formula to Stranded Costs Associated 
With Retail-Turned-Wholesale Customers and Retail Wheeling Customers

    OH Com, MO Com and KS Com maintain that the Commission's formula is 
inappropriate for calculating stranded costs associated with retail 
wheeling customers and/or retail-turned wholesale customers. They 
contend that the formula would be impractical to administer and would 
produce inaccurate results given the enormity of the calculations and 
assumptions involved. Suffolk County argues that the formula is flawed 
for retail-related stranded costs because the Commission cannot 
guarantee any retail rates into the future because it has no basis for 
even speculating about how retail rates may be changed by subsequent 
state action.

Commission Conclusion

    With respect to stranded costs caused by retail wheeling, the 
Commission determined in Order No. 888 that the formula was 
inappropriate, and that if the Commission had to determine stranded 
costs associated with retail wheeling it would do so on a case-by-case 
basis. <SUP>762 However, the formula does work for stranded costs 
associated with retail-turned-wholesale customers because the newly 
formed municipal utility would have the resources to engage in 
marketing or brokering and would have a marketable product. This stands 
in contrast to individual retail customers, most of whom are unlikely 
to have the resources to engage in marketing or brokering and would 
have very small amounts of energy for sale. Although the calculations 
necessary to estimate stranded costs associated with retail-turned-
wholesale customers are somewhat more involved than stranded costs 
associated with wholesale contracts, they are not impossible or overly 
burdensome. Accordingly, we affirm our finding in Order No. 888 that 
the formula is appropriate in the retail-turned-wholesale context.
---------------------------------------------------------------------------

    \762\ FERC Stats. & Regs. at 31,840; mimeo at 598.
---------------------------------------------------------------------------

Rehearing Requests

    Allegheny Power states that stranded cost recovery should not be 
permitted if a utility recovers large amounts through exit fees, then 
uses the freed capacity to make sales in the market at anything over 
variable costs. Allegheny Power argues that a utility with nuclear 
generation, which has a low variable cost, can dump power on the market 
because its fixed costs are subsidized by stranded cost recovery. 
Allegheny Power requests that the Commission recognize that this 
distortion of the competitive market should not be facilitated by 
stranded cost recovery.

Commission Conclusion

    Allegheny Power's concern that a utility recovering stranded costs 
will use those revenues to subsidize sales in the market at anything 
above variable costs is misplaced. In the power market, power pricing 
decisions are based on whether the utility can recover its variable 
cost, plus earn some contribution to capital costs. Stranded cost 
revenues are not relevant. This fact is demonstrated by considering the 
situation where no stranded cost revenues are provided to a utility 
with nuclear generation as described by Allegheny Power. The utility, 
in pricing power for off-system sales, would still face the same 
choice, i.e., make the sale and earn some minimal contribution to 
capital, or forego the sale and earn nothing. The Commission's decision 
to provide recovery of stranded costs does not change the economics 
involved in utility power pricing decisions, and does not lead to the 
type of market distortion that concerns Allegheny Power.

[[Page 12428]]

Rehearing Requests

    SBA asserts that determining the proper amount of stranded cost 
recovery is an integral step in the deregulation process.<SUP>763 It 
expresses concern that the revenues lost formula can be abused through 
the manipulation of the necessary financial statements of the parties 
and that such abuse could be harmful to small businesses. SBA requests 
that the Commission solicit its input, as well as the input of the 
small business community and small business organizations, when 
determining whether the proposed stranded cost recovery amount in a 
particular case is fundamentally fair in terms of maintaining a viable 
environment for small businesses.
---------------------------------------------------------------------------

    \763\ As discussed in Section VI., we will treat SBA's request 
as a motion for reconsideration.
---------------------------------------------------------------------------

Commission Conclusion

    In response to SBA's request, we note that SBA, or any interested 
small business organization, has the opportunity to provide input to 
the Commission in a particular stranded cost proceeding by filing a 
motion to intervene in that proceeding.<SUP>764
---------------------------------------------------------------------------

    \764\ 18 CFR 385.214 (1996).
---------------------------------------------------------------------------

10. Stranded Costs in the Context of Voluntary Restructuring
    No rehearing requests were filed on this issue. The Commission 
reaffirms that we are willing to consider case-specific proposals for 
dealing with stranded costs in the context of any restructuring 
proceedings that may be instituted by individual utilities.<SUP>765
---------------------------------------------------------------------------

    \765\ See FERC Stats. & Regs. at 31,845-46; mimeo at 614-15.
---------------------------------------------------------------------------

11. Accounting Treatment for Stranded Costs
    No rehearing requests were filed on this issue. The Commission 
reaffirms Order No. 888's treatment of this issue.<SUP>766
---------------------------------------------------------------------------

    \766\ See FERC Stats. & Regs. at 31,846-47; mimeo at 615-18.
---------------------------------------------------------------------------

12. Definitions, Application, and Summary
    In Order No. 888, we defined ``wholesale stranded cost'' in section 
35.26(b)(1) as follows:

    (1) Wholesale stranded cost means any legitimate, prudent and 
verifiable cost incurred by a public utility or a transmitting 
utility to provide service to:
    (i) a wholesale requirements customer that subsequently becomes, 
in whole or in part, an unbundled wholesale transmission services 
customer of such public utility or transmitting utility; or
    (ii) a retail customer, or a newly created wholesale power sales 
customer, that subsequently becomes, in whole or in part, an 
unbundled wholesale transmission services customer of such public 
utility or transmitting utility. <SUP>[767]
---------------------------------------------------------------------------

    \767\ Mimeo at 768.

We rejected requests by commenters in this proceeding to expand the 
definition to include the situation where a wholesale requirements 
customer or a retail-turned-wholesale customer ceases to purchase power 
from the utility without using the transmission services of that 
utility.<SUP>768 We explained that any costs that the utility might 
incur as a result of the loss of the requirements customer in this 
scenario would be outside the scope of this Rule. We noted that the 
premise of this Rule is that, where a customer uses Commission-mandated 
transmission access of its former power supplier to obtain power from a 
new generation supplier, the customer must pay the costs that were 
incurred to provide service to the customer under the prior regulatory 
regime. We indicated that if a customer leaves its utility supplier by 
exercising power supply options (such as access to another utility's 
transmission system or self-generation) that do not rely on access to 
the former seller's transmission, there is no nexus to the new open 
access rules.<SUP>769
---------------------------------------------------------------------------

    \768\ FERC Stats. & Regs. at 31,849-50; mimeo at 624-26. The 
definition of ``retail stranded cost'' contains a similar 
requirement that the retail customer must become, in whole or in 
part, an unbundled retail transmission services customer of the 
public utility from which the customer previously received bundled 
retail services. We said that we would retain it for the same 
reasons discussed above.
    \769\ As we clarify in this Order, there is not a sufficient 
nexus to Commission-required transmission access in such 
circumstances. The Commission's decision not to allow utilities to 
seek recovery of stranded costs under the provisions of Order No. 
888 if the customer leaves its historical power supplier by 
exercising power supply options that do not rely on access to the 
former supplier's transmission is based on the absence of a direct 
causal nexus between stranded costs and the availability and use of 
Commission-required transmission access. Self-generation and access 
to another utility's transmission system would have been options 
prior to the Rule.
---------------------------------------------------------------------------

    We also decided to retain the requirement that stranded costs be 
``legitimate, prudent and verifiable,'' rejecting requests by some 
commenters to eliminate the term ``prudent'' from the definition of 
stranded costs.<SUP>770 We explained that a determination that a 
utility had a reasonable expectation of continuing to serve a customer 
would not, in all circumstances, mean that costs incurred by the 
utility were prudent. We said that prudence of costs, depending upon 
the facts in a specific case, may include different things: e.g., 
prudence in operation and maintenance of a plant; prudence in 
continuing to own a plant when cheaper alternatives become available; 
prudence in entering into purchased power contracts, or continuing such 
contracts when buy-outs or buy-downs of the contracts would result in 
savings. We concluded that the Commission cannot make a blanket 
assumption that all claimed stranded costs will have been prudently 
incurred, but we clarified that we do not intend to relitigate the 
prudence of costs previously recovered.
---------------------------------------------------------------------------

    \770\ FERC Stats. & Regs. at 31,850; mimeo at 626-27.
---------------------------------------------------------------------------

Rehearing Requests--Definitions of ``Wholesale Stranded Cost'' and 
``Wholesale Requirements Contract''

    As discussed in Sections IV.J.1 and IV.J.6, supra, a number of 
entities ask the Commission to expand the scope of stranded cost 
recovery allowed under the Rule to include ``bypass'' situations (i.e., 
situations in which a departing customer does not use its former 
supplier's transmission system to reach another supplier). Coalition 
for Economic Competition asks the Commission to revise the definition 
of ``wholesale stranded cost'' to accomplish that result. It notes, for 
example, that the reference in the definition to ``newly created 
wholesale power sales customer'' creates an ambiguity and may provide a 
loophole to evade stranded costs through municipal annexation.
    El Paso expresses concern that a retail-turned-wholesale customer 
could attempt to avoid its stranded cost responsibility simply by 
having its outside power supplier be the ``wholesale transmission 
customer'' (i.e., the entity that formally requests transmission 
service from the transmitting utility). El Paso asks the Commission to 
clarify that a retail-turned-wholesale customer is responsible to the 
transmitting utility for stranded costs regardless of whether it or its 
outside power supplier is the ``transmission customer'' of the 
transmitting utility. El Paso asks the Commission to revise section 
35.26(c)(1)(vii) (which presently provides for recovery from retail-
turned-wholesale customers through section 205-206 or 211-212 wholesale 
transmission rates) to provide for the recovery of stranded costs 
directly from retail-turned-wholesale customers (through an exit fee or 
lump sum payment).
    Utilities For Improved Transition asks the Commission to expand the 
definition to include costs incurred to provide service to ``a 
wholesale requirements customer that loses retail load because of 
retail wheeling,

[[Page 12429]]

municipalization of retail load, the creation of a new customer, or 
because retail customers have bypassed its system through transmission 
or distribution taps to other suppliers or by other means.'' <SUP>771 
Utilities For Improved Transition argues that, in the case of retail 
wheeling and municipalization, these costs are incurred because of open 
access tariffs. It further submits that the Commission also should 
include costs incurred because of taps (interconnections) to other 
systems to avoid encouraging uneconomic bypass as a way to avoid 
stranded cost charges.
---------------------------------------------------------------------------

    \771\ Utilities For Improved Transition at 17.
---------------------------------------------------------------------------

    APPA expresses concern that the definition in section 35.26(b)(4) 
of ``wholesale requirements contract'' as ``a contract under which a 
public utility or transmitting utility provides any portion of a 
customer's bundled wholesale power requirements'' could be read as 
including a bundled sale of capacity regardless of whether the seller 
undertook to meet the customer's load growth. As a result, APPA submits 
that the definition could include coordination arrangements. It is 
APPA's position that the Commission could not, or should not, have 
intended to allow stranded cost recovery for such contracts. APPA asks 
the Commission to specify on rehearing that a ``wholesale requirements 
contract'' is a bundled power and transmission arrangement that 
includes the obligation to meet some or all of the customer's load 
growth, and that all other services are coordination arrangements to 
which the stranded cost recovery rules do not apply.

Commission Conclusion

    We will reject the requests for rehearing that ask the Commission 
to expand the scope of stranded cost recovery allowed under the Rule to 
include situations in which a wholesale requirements customer (or a 
retail-turned-wholesale customer) ceases to purchase power from the 
utility without using the transmission services of that utility. As we 
explain in Sections IV.J.1 and IV.J.6, supra, any costs that the 
utility might incur as a result of the loss of the customer in these 
scenarios would be outside the scope of Order No. 888. However, as 
discussed in Section IV.J.6, we grant rehearing on the municipal 
annexation issue.
    We share El Paso's concern that a retail-turned-wholesale customer 
should not be able to avoid its stranded cost responsibility simply by 
having its outside power supplier be the entity that formally requests 
unbundled transmission service from the utility. As we explain in 
Section IV.J.6, supra, in response to a similar concern expressed by 
Puget, we have revised the definition of ``wholesale stranded cost'' in 
section 35.26(b)(1)(ii) to cover this situation. As revised, that 
section provides that ``[w]holesale stranded cost means any legitimate, 
prudent and verifiable cost incurred by a public utility or a 
transmitting utility to provide service to: * * *. (ii) a retail 
customer that subsequently becomes, either directly or through another 
wholesale transmission purchaser, an unbundled wholesale transmission 
services customer of such public utility or transmitting utility.
    We will deny Utilities For Improved Transition's request that the 
Commission expand the definition to include costs incurred to provide 
service to ``a wholesale requirements customer that loses retail load 
because of retail wheeling, municipalization of retail load, the 
creation of a new customer, or because retail customers have bypassed 
its system through transmission or distribution taps to other suppliers 
or by other means.'' Utilities For Improved Transition, in effect, is 
asking that the Commission allow the recovery of costs that may be 
stranded due to the loss of an indirect customer and to expand the 
scope of the ``wholesale stranded costs'' for which Order No. 888 
provides an opportunity for recovery. As we discuss in Section IV.J.1, 
supra, the Commission does not believe it is appropriate to expand the 
scope of the stranded cost recovery opportunity provided under this 
Rule to include costs that may be stranded due to the loss of an 
indirect customer (i.e., a customer of a wholesale requirements 
customer of the utility). The reasonable expectation analysis would 
apply only to the direct wholesale requirements customer of the 
utility, not to the indirect customer. A utility may seek to recover 
stranded costs from a direct wholesale customer (subject to the 
requirements of the Rule), but it is up to the direct wholesale 
customer, through its contracts with its customers or through the 
appropriate regulatory authority, to seek to recover stranded costs 
from its customers.
    In response to APPA's argument that the definition of ``wholesale 
requirements contract'' in new section 35.26(b)(4) of the Commission's 
regulations could be read as including coordination arrangements, we 
clarify that it does not. The opportunity to recover stranded costs 
applies only to bundled power contracts where the utility can 
demonstrate that it incurred costs to provide service to a customer 
based on a reasonable expectation of continuing service to the customer 
beyond the contract term. Coordination arrangements could not meet the 
cost incurrence and reasonable expectation prerequisites of Order No. 
888, and therefore a customer served under such an arrangement would 
not be subject to stranded cost charges.

Rehearing Requests--Relitigation of Prudence

    A number of entities express concern that, notwithstanding the 
Commission's stated preference not to relitigate prudence, Order No. 
888 leaves the door open for subsequent litigation of prudence issues. 
Centerior asks the Commission either to remove ``prudent'' from the 
definition or to clarify that ``prudent'' means all costs found 
prudently incurred by the state commissions. Centerior asks the 
Commission not to relitigate prudence in the operation and maintenance 
of a plant or the prudence of continuing to own a plant when cheaper 
alternatives become available. Other entities (including EEI, PSE&G, 
and Nuclear Energy Institute) similarly ask the Commission to clarify 
that it does not intend to relitigate costs that are already in rates 
when calculating the revenue stream estimate. Nuclear Energy Institute 
states that, in the case of nuclear plants, significant prudence 
proceedings have already been conducted and, by definition, the 
embedded capital costs included in current rates to customers are 
prudent.
    PSE&G recommends that if costs that form the basis for a utility's 
claimed stranded costs are already included in filed rates and are no 
longer subject to refund, those costs should be treated as per se 
prudent. Southern states that if the Commission does not strike the 
word ``prudent'' from the definition of stranded costs, at a minimum it 
should modify the Rule to establish a rebuttable presumption of 
prudence that must be overcome by the departing customer.
    PSE&G and Carolina P&L submit that if prudence challenges under the 
Rule are retained on rehearing, they should be subject to the same 
standards as any other prudence challenge, namely the ``reasonable 
person test'' under which prudent costs are those ``which a reasonable 
utility management * * * would have made, in good faith, under the same 
circumstances, and at the relevant point in time.'' <SUP>772 PSE&G and 
Carolina P&L ask the Commission to limit the prudence review to the 
reasonableness of the costs that were incurred to provide wholesale 
requirements service based on the

[[Page 12430]]

utility's reasonable expectation of continued service. They ask the 
Commission to clarify that it will not permit prudence proceedings to 
devolve into collateral attacks on stranded cost recovery and unfocused 
debates on the sufficiency of the utility's efforts to adapt to changes 
in the industry, such as its decisions on staffing reductions and asset 
write-offs.
---------------------------------------------------------------------------

    \772\ Both note that this is the prudence standard that the 
Commission applied in Order No. 636.
---------------------------------------------------------------------------

Commission Conclusion

    In Order No. 888, we specifically stated that we do not intend to 
relitigate the prudence of costs previously recovered but that we would 
not preclude parties from raising prudence in stranded cost 
proceedings. Because we believe that this approach adequately ensures 
that the prudence of costs previously recovered at this Commission or a 
state commission will not be relitigated for stranded cost purposes, we 
will reject the rehearing requests that seek elimination of the term 
``prudent'' from the definition of stranded costs.<SUP>773 However, we 
make certain clarifications below in response to the rehearing 
petitions.
---------------------------------------------------------------------------

    \773\ For the same reason, we will reject Southern's request 
that we establish a rebuttable presumption of prudence that must be 
overcome by the departing customer.
---------------------------------------------------------------------------

    As an initial matter, we clarify that the Commission's 
determination in Order No. 888, which is reaffirmed here, is the same 
approach the Commission traditionally has followed regarding prudence 
matters.<SUP>774 Costs are assumed prudent unless a party or the 
Commission raises a serious doubt as to prudence; then the burden is on 
the utility to prove that costs were prudently incurred.<SUP>775 If 
costs have previously been recovered in rates (either following an 
explicit prudence determination or based on an implicit assumption of 
prudence because no one raised prudence), they cannot be relitigated. 
However, if prudence has not previously been litigated or if certain 
costs or activities have become imprudent,<SUP>776 a party may raise 
the issue as it pertains to future cost recovery.<SUP>777 The 
Commission intends to apply the same prudence standards with regard to 
future cost recovery, including stranded costs.
---------------------------------------------------------------------------

    \774\ See Minnesota Power & Light Company, Opinion No. 86, 11 
FERC para. 61,312 at 61,644-45 (1980).
    \775\ Id. at 61,644; Anaheim Riverside, et al. v. FERC, 669 F.2d 
799, 809 (D.C. Cir. 1981).
    \776\ A utility has an ongoing prudence obligation. As pointed 
out in Order No. 888, although an investment or a contract may have 
been prudently incurred, it may become imprudent at a later point in 
time not to dispose of assets or not to buy-out contracts that have 
become uneconomic, assuming this results in net benefits to 
customers.
    \777\ See Canal Electric Company, 47 FERC para. 61,044 at 
61,127, reh'g denied, 49 FERC para. 61,069 (1989) (if a party raises 
prudence issues in a later proceeding, any future finding concerning 
prudence will have no effect on past rates).
---------------------------------------------------------------------------

    We further clarify that we do not intend to relitigate, for 
purposes of stranded cost determinations involving retail-turned-
wholesale customers or unbundled retail customers, the prudence of 
costs for which rate recovery has been allowed by state commissions. 
Similarly, in calculating the revenue stream estimate, we do not intend 
to relitigate the prudence of any costs for which rate recovery has 
been allowed by this Commission or a state commission.<SUP>778
---------------------------------------------------------------------------

    \778\ Although we will not go so far as to characterize these 
costs as ``per se prudent'' (as requested by PSE&G), in effect, the 
result is the same because we will not allow the prudence of such 
costs to be relitigated.
---------------------------------------------------------------------------

    In response to PSE&G and Carolina P&L, we also clarify that, in 
cases in which we do entertain stranded cost claims, the standard to be 
used for reviewing the prudence of a utility's costs is the 
``reasonable person'' test that we apply in other contexts.<SUP>779 
This test gives utility managers ``broad discretion in conducting their 
business affairs and in incurring costs necessary to provide services 
to their customers.'' <SUP>780 It asks whether the costs are those 
``which a reasonable utility management * * * would have made, in good 
faith, under the same circumstances, and at the relevant point in 
time.'' <SUP>781 We clarify that we do not intend to permit prudence 
proceedings to become an opportunity for collateral attacks on stranded 
cost recovery.
---------------------------------------------------------------------------

    \779\ See New England Power Company, 31 FERC para. 61,047 at 
61,081-84 (1985), aff'd sub nom., Violet v. FERC, 800 F.2d 280, 282-
83 (1st Cir. 1986). We note that this is the same standard that the 
Commission has used for reviewing the prudence of a pipeline's Order 
No. 636 gas supply realignment costs. See Texas Eastern Transmission 
Corporation, 65 FERC para. 61,363 (1993).
    \780\ New England Power Company, 31 FERC at 61,084.
    \781\ Id.
---------------------------------------------------------------------------

K. Other

1. Information Reporting Requirements for Public Utilities
    In the Final Rule, the Commission indicated that it will not now 
eliminate the public disclosure of allegedly competitively sensitive, 
proprietary, or otherwise confidential data submitted to the Commission 
on Form No. 1, as well as on other Commission forms. <SUP>782 It 
explained that the information it collects from public utilities is 
necessary to carry out its jurisdictional responsibilities and is used, 
among other things, to evaluate the reasonableness of cost-based rates 
subject to the Commission's jurisdiction and the operation of power 
markets.<SUP>783 Moreover, the Commission noted its explanation in 
ConEd:

    \782\ FERC Stats. & Regs. at 31,851-52; mimeo at 631-32.
    \783\ See, e.g., Consolidated Edison Company of New York, Inc. 
and Central Hudson Gas & Electric Corp., 72 FERC para. 61,184 at 
61,891 (1995) (ConEd).
---------------------------------------------------------------------------

[r]eports required to be submitted by Commission rule and necessary 
for the Commission's jurisdictional activities are considered public 
information. 18 C.F.R. Sec. 388.106. In addition, the Commission has 
long required jurisdictional utilities to submit Form 1 data on a 
form that states on its cover that the Commission does not consider 
the material to be confidential. [<SUP>784]
---------------------------------------------------------------------------

    \784\ 72 FERC at 61,891.

    The Commission expressed sensitivity to the lack of symmetry in the 
generation information we require from traditional public utilities, 
particularly those that have market-based rate authority, and the 
generation information required from other public utilities (e.g., 
public utility marketers) authorized to sell at market-based rates, but 
explained that the record in the proceeding is insufficiently developed 
to make and support a well-informed decision requiring a different 
reporting scheme, particularly given the industry's current rapid pace 
of change. Also, the Commission indicated that it was not persuaded 
that the burdens borne by traditional public utilities (primarily 
annual reports submitted months after-the-fact) are impairing the 
competitiveness of these utilities so much that we must act hastily 
now, instead of deferring a decision to a more appropriate proceeding.
    However, the Commission stated that it will monitor its reporting 
requirements to make sure that they are needed, fair to all segments of 
the industry, and consistent with the workings of a competitive 
environment.

Rehearing Requests

    Allegheny asserts that this proceeding is the proper forum to 
evaluate the public disclosure of information required from public 
utilities because it is necessary to avoid disparate treatment of 
market participants that violates the comparability standard and leads 
to market distortions. It argues that the Commission should eliminate 
the requirement to file data on Form No. 1 and other informational 
filings, or alternatively the Commission should protect the information 
as proprietary and confidential.
    Centerior argues that the Commission should eliminate the public 
disclosure of the cost-based generation rates and provide for symmetry 
between the information provided by public utilities

[[Page 12431]]

and power marketers by eliminating the reporting requirements.
    EEI indicates that it intends to petition the Commission for 
further action on information reporting requirements in the near 
future. It adds that it seeks to work with the Commission in 
streamlining the reporting process and in creating a level playing 
field.

Commission Conclusion

    We are not persuaded that the information reporting requirements 
for public utilities need to be changed at this time. Very simply, it 
is premature to take such a step at a time when much of the industry is 
still under cost-based rate regulation for sales of electric energy and 
when corporate restructuring, including utility mergers, is occurring 
at a rapid pace. On rehearing, entities have merely reiterated the 
arguments that we previously addressed in the Final Rule and have 
presented no evidence that the competitiveness of traditional public 
utilities is being impaired by their having to submit primarily annual 
reports that are filed months after the fact. Accordingly, we will 
continue to require public utilities to submit the information required 
by our rules and regulations and we will monitor our reporting 
requirements as the industry environment continues to change.
2. Small Utilities
    The Commission noted that it was sympathetic to the array of 
concerns raised by small public utilities and small transmission 
customers and explained that the regulations it was adopting include 
waiver provisions under which public utilities and transmission 
customers, and non-public utility entities seeking exemption from the 
reciprocity condition, may file requests for waivers from all or part 
of the Commission's regulations or for special treatment.<SUP>785 
However, the Commission explained, it is difficult to imagine any 
circumstance that would justify waiving the requirements of this Rule 
for any public utility that is also a control area operator.
---------------------------------------------------------------------------

    \785\ FERC Stats. & Regs. at 31,853-54; mimeo at 636-38. The 
Commission also noted that non-public utility entities could request 
that the Commission find that they can satisfy the reciprocity 
condition without meeting all or some of the requirements that 
public utilities must meet.
---------------------------------------------------------------------------

    The Commission recognized that it might be a financial burden on 
small public utilities to unbundle generation from transmission, follow 
standards of conduct that separate transmission personnel from 
wholesale marketing personnel, and maintain an OASIS. In addition, the 
Commission explained that for small public utilities that own no 
generation and buy at wholesale on a radial transmission line from 
another utility's grid or if their service territory is part of another 
utility's control area, the small public utility should be permitted to 
make a showing that it should be exempt from all or some of the Rule.
    The Commission further explained that because the possible 
scenarios under which small entities may seek waivers from the Final 
Rule are diverse, they are not susceptible to resolution on a generic 
basis and the Commission will require applications and fact-specific 
determinations in each instance.
    In addition, the Commission indicated that it will apply the same 
standards to any entity seeking a waiver. The Commission explained that 
this includes public utilities seeking waiver of some or all of the 
requirements of the Rule, as well as non-public utilities seeking 
waiver of the reciprocity provisions contained in the pro forma open 
access tariff. The Commission concluded that it would not apply the 
open access reciprocity provision to small non-public utilities that 
are not control area operators and either do not own or control 
transmission or have transmission that no one is likely to ask to use. 
However, the Commission explained that they will have to apply for this 
waiver and demonstrate that they qualify for the waiver.

Rehearing Requests

    APPA asserts that absent a finding that a non-public utility has 
market power or has exhibited undue discrimination, the non-public 
utility should be granted a waiver.
    Michigan Systems asks that the Commission modify the Rule to 
provide a blanket waiver for systems that by their nature cannot have 
market power over transmission and do not have the personnel to 
separate functions. It also asserts that the Final Rule waiver 
procedure is cumbersome and time consuming.
    Tallahassee asks the Commission to clarify that it will liberally 
apply its waiver policy to small public utilities even if they run a 
control area. It asserts that the proper focus of concerns over 
competition are a utility's size, its ability to manipulate the market, 
and how it operates its control room.
    CAMU asks the Commission to clarify that the small utilities waiver 
will be generally available to those entities lacking market power 
because only utilities with market power are capable of subverting the 
transmission market.

Commission Conclusion

    The issues raised with respect to waivers for small utilities are 
more appropriately addressed in individual fact-specific proceedings. 
As we explained in the Final Rule,

[b]ecause the possible scenarios under which small entities may seek 
waivers from the Final Rule are diverse, they are not susceptible to 
resolution on a generic basis and we will require applications and 
fact-specific determinations in each instance. We note here that any 
waivers that we may grant depend upon the facts presented in each 
case.<SUP>[786]

    \786\ FERC Stats. & Regs. at 31,854; mimeo at 637-38.
---------------------------------------------------------------------------

Indeed, we have granted a variety of waiver requests by small utilities 
since issuance of the Final Rule.<SUP>787
---------------------------------------------------------------------------

    \787\ Black Creek Hydro, Inc. (Black Creek), 77 FERC para. 
61,232 (1996); Midwest Energy, Inc., 77 FERC para. 61,208 (1996).
---------------------------------------------------------------------------

3. Regional Transmission Groups
a. Incentives for RTGs To Form and Resolve Regional Transmission Issues
    In the Final Rule, the Commission expressed its continued support 
for the development of RTGs and encouraged regional tariffs.<SUP>788 To 
further encourage the development of RTGs, the Commission stated that 
it will accept regional open access transmission tariffs developed by 
RTGs that are consistent with the objectives of this Rule.
---------------------------------------------------------------------------

    \788\ FERC Stats. & Regs. at 31,854-55; mimeo at 640.
---------------------------------------------------------------------------

b. Deference To RTGs to Develop Regional Tariffs and Prices
    In the Final Rule, the Commission indicated its intent to give 
deference to the planning, dispute resolution, and decisionmaking 
processes of an RTG. <SUP>789 With respect to pricing proposals 
submitted by RTGs, the Commission stated that RTGs may be able to 
develop solutions to such problems as loop flows through innovative 
flow-based pricing methodologies.
---------------------------------------------------------------------------

    \789\ FERC Stats. & Regs. at 31,855; mimeo at 642.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
4. Pacific Northwest
    In the Final Rule, the Commission encouraged the filing of regional 
open access transmission tariffs.<SUP>790 It also explained that the 
Final Rule pro forma tariff contains provisions allowing utilities to 
modify tariff terms to reflect prevailing regional practices. The 
Commission concluded that this should permit entities in the Pacific 
Northwest

[[Page 12432]]

to address unique circumstances that exist in the Pacific Northwest and 
to incorporate prevailing regional practices (e.g., treatment of 
hydropower generation in the priority of dispatch) into their open 
access transmission tariffs.
---------------------------------------------------------------------------

    \790\ FERC Stats. & Regs. at 31,856; mimeo at 644-45.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
5. Power Marketing Agencies
a. Bonneville Power Administration (BPA)
    In the Final Rule, the Commission stated that BPA is not a public 
utility under section 201(e) of the FPA and, thus, is not subject to 
the requirements of this Rule to put the Final Rule pro forma tariff 
into effect.<SUP>791 However, the Commission indicated three 
circumstances under which the Commission may review BPA's transmission 
access and pricing policies.
---------------------------------------------------------------------------

    \791\ FERC Stats. & Regs. at 31,857-58; mimeo at 648-49.
---------------------------------------------------------------------------

    With respect to stranded costs, the Commission clarified that the 
Rule addresses only stranded costs recovered by public utilities under 
the FPA and transmitting utilities (including BPA) that are subject to 
mandatory transmission requests under FPA section 211. It explained 
that the Rule does not address stranded cost recovery by BPA under the 
Northwest Power Act.

Rehearing Requests

    BPA asks the Commission to clarify that it did not intend to 
address stranded cost recovery by BPA under either the Northwest Power 
Act or section 212(i) of the FPA. If Order No. 888 is intended to 
govern stranded cost recovery by BPA in the case of Commission-ordered 
transmission under section 211, BPA asks the Commission for an 
opportunity to brief the issue on rehearing.

Commission Conclusion

    We clarify that our review of stranded cost recovery by BPA would 
take into account the statutory requirements of the Northwest Power Act 
and the other authorities under which we regulate BPA (e.g., DOE 
delegation for interim rate approval) and/or section 212(i), as 
appropriate.
b. Other Power Marketing Agencies
    In the Final Rule, the Commission explained that Federal power 
marketing agencies (PMAs) are not public utilities as defined under 
section 201(e) of the FPA and, thus, are not required by this Rule to 
file non-discriminatory open access transmission tariffs.<SUP>792 
However, the Commission did state that to the extent a PMA receives 
open access transmission service from a public utility, it is subject 
to the reciprocity provisions in the utility's pro forma 
tariff.<SUP>793
---------------------------------------------------------------------------

    \792\ The Commission noted, however, that PMAs are transmitting 
utilities subject to requests for mandatory transmission services 
under section 211 of the FPA.
    \793\ FERC Stats. & Regs. at 31,858; mimeo at 650-51.
---------------------------------------------------------------------------

    With respect to SEPA's concern that the proposed point-to-point 
tariff has a one MW minimum scheduling requirement, but many of its 
customers have loads of less than one MW, the Commission clarified that 
the Final Rule pro forma tariff will allow SEPA to continue to schedule 
service for these customers. The Commission also clarified that SEPA, 
as a seller of power to multiple purchasers inside several control 
areas, is eligible to receive network service.

Rehearing Requests

    Entergy asks the Commission to clarify that SEPA can obtain network 
service only in the same manner as any other customer and that there 
was no intent in the Rule to create a special type of network service 
for SEPA.

Commission Conclusion

    We will clarify that for purposes of obtaining network service SEPA 
is to be treated as any other customer.
6. Tennessee Valley Authority
    In the Final Rule, the Commission stated that TVA is not a public 
utility under section 201(e) of the FPA and, thus, is not required to 
file a non-discriminatory open access transmission tariff under this 
Rule.<SUP>794 However, the Commission explained, if TVA receives open 
access transmission service from a public utility, it is subject to the 
reciprocity provision in the utility's pro forma tariff.<SUP>795
---------------------------------------------------------------------------

    \794\ The Commission noted, however, that TVA is a transmitting 
utility subject to requests for mandatory transmission services 
under section 211 of the FPA.
    \795\ FERC Stats. & Regs. at 31,858-59; mimeo at 651-52.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
7. Hydroelectric Power
Non-Firm Transactions
    In the Final Rule, the Commission explained that it will permit 
entities to incorporate prevailing regional practices (e.g., treatment 
of hydropower generation in the priority of dispatch) into regional 
open access transmission tariffs.<SUP>796 This, the Commission 
indicated, should permit entities in a region to resolve concerns over 
the scheduling of non-firm hydropower.
---------------------------------------------------------------------------

    \796\ FERC Stats. & Regs. at 31,859; mimeo at 654-55.
---------------------------------------------------------------------------

Commission's Licensing Practices

    The Commission explained that the issues raised by National 
Hydropower with respect to the Commission's hydroelectric licensing 
practices are beyond the scope of this rulemaking. The Commission also 
noted that these issues were raised in a petition to the Commission to 
revise hydroelectric licensing procedures, filed on July 10, 1995. That 
is the proper proceeding, the Commission explained, in which to address 
the Commission's hydroelectric licensing practices.

Rehearing Requests

    No requests for rehearing addressed this matter.
8. Residential Customers
    In the Final Rule, the Commission stated that it was convinced that 
the proposed changes for wholesale markets will benefit residential 
consumers. <SUP>797 Moreover, the Commission explained that the Rule 
does not require retail transmission access for retail customers of any 
size and does not require any changes in programs such as assistance to 
low-income and elderly consumers and weatherization and energy 
conservation, which are, and will remain, under the jurisdiction of the 
individual states. The Commission further noted that the Rule contains 
several safeguards to maintain the ability of states to impose 
conditions on retail access, such as conditions that help to protect 
residential customers from becoming the residual payer of stranded 
costs.
---------------------------------------------------------------------------

    \797\ FERC Stats. & Regs. at 31,860; mimeo at 656.
---------------------------------------------------------------------------

Rehearing Requests

    No requests for rehearing addressed this matter.
9. Miscellaneous Issues
Unconstitutional Taking of Property
    Union Electric declares that the imposition of an onerous regime of 
mandates governing what utilities must and must not do with their own 
property constitutes an unconstitutional taking of their property in 
violation of the takings clause.

[[Page 12433]]

Commission Conclusion

    Union Electric has provided no valid legal or factual basis to 
support its arguments that our final orders result in an 
unconstitutional taking of property in violation of the takings clause. 
We have a statutory obligation under the FPA to remedy undue 
discrimination in the transmission or sale of electric energy subject 
to our jurisdiction. In Order No. 888, we concluded that unduly 
discriminatory and anticompetitive practices exist today in the 
electric industry and that such practices will increase as competitive 
pressures continue to grow in the industry.<SUP>798 Accordingly, we 
exercised our remedial authority by issuing Order Nos. 888 and 889 to 
ensure that unduly discriminatory practices can no longer 
occur.<SUP>799
---------------------------------------------------------------------------

    \798\ FERC Stats. & Regs. at 31,682-84; mimeo at 136-142.
    \799\ Union Electric argues that
    [t]he dramatic changes in the regulatory scheme set forth in the 
final rules impose extensive constraints on Union Electric's use of 
its own property, forcing Union Electric to throw open its 
transmission system to use by third parties, dictating the terms and 
conditions of that usage and, in the process, providing for the 
physical occupation of Union Electric's transmission system by third 
parties' facilities and power. (Union Electric at 59).
    However, as Union Electric's own words demonstrate, these so-
called dramatic changes are no more than a summary of the 
Commission's current authority and the Commission's current 
regulation of public utilities. Under the FPA, Union Electric can 
only provide non-unduly-discriminatory jurisdictional services to 
third parties and must obtain Commission approval of the rates, 
terms and conditions pursuant to which it provides such service. 
Moreover, under Order No. 888, third parties may ``physically 
occupy'' Union Electric's transmission system only pursuant to the 
terms of Union Electric's tariff and contracts entered into with 
Union Electric, just as third parties previously had the right to 
``physically occupy'' its transmission system.
    Finally, we are confused about Union Electric's argument in that 
in the pending merger proceeding involving its proposed merger with 
Central Illinois, it argues that the open access tariff of the 
merged company will be used to mitigate market power. See El Paso 
Electric Company and Central and South West Services Inc., 68 FERC 
para. 61,181 at 61,914 (1994), dismissed, 72 FERC para. 61,292 
(1995). Union Electric cannot argue that the tariff mitigates market 
power at the same time it argues that the requirement to have the 
tariff is prohibited as an unconstitutional taking of property.
---------------------------------------------------------------------------

    In exercising our remedial authority, we did not alter the 
traditional principle that a utility is entitled to a reasonable 
opportunity to recover its prudently incurred costs.<SUP>800 Union 
Electric has provided no evidence that it will not be adequately 
compensated for whatever services it may provide on its system 
following the effectiveness of Order Nos. 888 and 889. To the extent a 
third party uses Union Electric's transmission system, it must still 
compensate Union Electric for that usage, as has happened in the past. 
There simply cannot be an unconstitutional taking of property when 
public utilities continue to have the right to file for and receive 
rates that provide them a reasonable opportunity to recover their 
prudently incurred costs. Indeed, as the Supreme Court has explained, 
``[a]ll that is protected against, in a constitutional sense, is that 
the rates fixed by the Commission be higher than a confiscatory 
level.'' <SUP>801 Union Electric has made no showing that Order Nos. 
888 and 889 will result in its rates being set at a confiscatory level. 
Furthermore, the rate that Union Electric may charge for transmission 
service is currently before the Commission in Docket No. OA96-50-000 
and Union Electric should make arguments regarding the reasonableness 
of its transmission rate in that proceeding. <SUP>802 Moreover, Union 
Electric is free to propose changes to the rate it charges for 
transmission from time to time to ensure that it is being fairly 
compensated for its investment in its transmission system, as well as 
any expenses it incurs in providing such service.
---------------------------------------------------------------------------

    \800\ See, e.g., FPC v. Hope Natural Gas Company, 320 U.S. 591 
(1944). Moreover, to the extent Union Electric's facilities are used 
for public service, Union Electric is entitled to recover all 
prudently invested capital in the public utility enterprise. We have 
not changed that principle.
    \801\ FPC v. Texaco, 417 U.S. 380, 391-92 (1974); see also FPC 
v. Natural Gas Pipeline Co., 315 U.S. 575, 585 (1942).
    \802\ All public utilities subject to Commission jurisdiction 
were required to file open access compliance tariffs, including the 
rate to be charged for various types of transmission service, by 
July 9, 1996.
---------------------------------------------------------------------------

Section 206 Complaints

    Cleveland states that, unfortunately, it has suffered significantly 
because of denied transmission access and the inefficacy of long-
delayed enforcement relief under section 206 of the FPA. Thus, 
Cleveland states that the Commission must announce its intention to 
enforce transmission and related obligations and, having made that 
pronouncement, take whatever steps are necessary to do so.
    TAPS states that throughout the Final Rule the Commission points to 
complaint procedures to redress complaints against transmission 
providers' open access tariffs and argues that the Commission must 
clarify that these complaints will receive expedited treatment.

Commission Conclusion

    The Commission has a statutory obligation to act if it finds, upon 
its own motion or upon complaint, that any rate, charges, or 
classification demanded, observed, charged, or collected by any public 
utility, or that any rule, regulation, practice, or contract affecting 
such rate, charge, or classification is unjust, unreasonable, unduly 
discriminatory or preferential, and to determine the just and 
reasonable rate, charge, classification, rule, regulation, practice, or 
contract to be thereafter observed. Moreover, section 206(b) of the FPA 
requires that whenever the Commission institutes a proceeding under 
this section it must establish a refund effective date. In carrying out 
its obligations under section 206 of the FPA, the Commission acts as 
expeditiously as is possible, given the complexities of the issues at 
hand, its other workload and its level of staffing. The Commission will 
continue to work as expeditiously as possible in resolving section 206 
proceedings, as well as in resolving all of the other matters that come 
before it. Given the critical importance of timely, comparable 
transmission access in fostering competitive wholesale power markets, 
the Commission intends to vigorously enforce utilities' open access 
obligations. <SUP>803
---------------------------------------------------------------------------

    \803\ With specific regard to Cleveland and CEI, we note that 
the Commission has expended considerable resources over the years 
dealing with and resolving a significant number of section 205 and 
206 proceedings in which these companies contested a plethora of 
issues. As the D.C. Circuit noted, these two entities have a 
particularly hostile relationship. City of Cleveland v. FERC, 773 
F.2d 1368, 1371 (1985). This has led to a situation where these 
contentious entities are more likely to contest issues before the 
Commission than to resolve them. Since 1993 alone, the Commission 
has addressed and resolved at least 9 proceedings involving disputes 
between Cleveland and CEI. Indeed, at this time, the Commission has 
only several ongoing proceedings involving disputes between these 
entities. In addition, the parties are in disagreement over 
transmission issues in the pending merger application involving CEI 
and Ohio Edison.
---------------------------------------------------------------------------

    We would emphasize that filing complaints with the Commission is 
not the only avenue that transmission customers (or potential 
customers) can pursue to raise their concerns. Under the Open Access 
Transmission Tariff, parties can and should avail themselves of the 
Dispute Resolution Procedures set forth in section 12 of the pro forma 
tariff. This section provides that an arbitrator must render a decision 
and notify the parties within ninety days of appointment.

NRC Remedial Orders

    Cleveland asks that the Commission clarify that directives 
requiring non-discriminatory treatment of transmission customers are 
not intended to override, but are expected to accommodate, valid 
remedial orders of the NRC imposed in the form of nuclear license 
conditions.

[[Page 12434]]

Commission Conclusion

    We will deny Cleveland's requested clarification because it is 
overly broad. However, we do clarify that we view our jurisdiction 
under the FPA and the NRC's jurisdiction as complementary. In that 
regard, a utility subject to the Commission's jurisdiction and to the 
NRC's jurisdiction would have to comply with the orders of both 
commissions. Moreover, just as the NRC cannot and does not enforce this 
Commission's orders, it is not within our jurisdiction to enforce 
orders of the NRC. In the event that an entity believes that it must, 
but cannot, comply with separate orders issued by this Commission and 
the NRC, it should present evidence to this Commission and/or the NRC 
of such a conflict. To the extent necessary and appropriate, we would 
attempt to resolve any such conflicts subject to our jurisdiction under 
the FPA.

Retail Customers' Future Access to Transmission Capacity

    IL Industrials states that the Commission should fashion safeguards 
to prevent monopolization of transmission capacity by wholesale 
customers before retail customers are entitled to engage in direct 
access. Alternatively, IL Industrials states that the Commission should 
specify that this issue will be addressed in the CRT NOPR proceeding 
and that contracts or other arrangements affecting available 
transmission capacity will be subject to safeguards to protect retail 
customer transmission access.

Commission Conclusion

    This matter is beyond the scope of this proceeding. We have no way 
of ascertaining the transmission capacity that a retail customer may 
require in the future should it become entitled to engage in direct 
access through a state-approved program or voluntary action by its 
current transmission provider. We cannot require a transmission 
provider to keep transmission capacity available for all possible 
transactions that a retail customer may possibly enter into in the 
future. Just as transmission customers must take the system as it 
exists at the time of a request, so must future potential transmission 
customers take the system as it exists at the time of their request.

Transaction Accommodation Arrangements

    NCMPA argues that the Commission failed to address the problem of 
market power arising from a transmission provider's control over 
transaction accommodation arrangements, which it states are 
arrangements needed by transmission dependent utilities to accommodate 
third-party transactions within an existing power supply relationship 
between the TDU and the transmission provider. NCMPA explains that this 
problem is most apparent where there is a comprehensive power supply 
relationship that purports to establish most or all of the TDU's bulk 
power needs. For example, NCMPA points out that because of Duke Power 
Company's control over transaction accommodation arrangements, NCMPA 
has been frustrated in its attempts to pursue beneficial bulk power 
transactions with parties other than Duke. NCMPA asks that the 
Commission require transmission providers to provide these arrangements 
on a comparable basis, state that it will take prompt action to remedy 
a denial of comparable arrangements, and require that any utility 
seeking specific permission for any action premised on the mitigation 
of market power to demonstrate that it has offered comparable 
transaction accommodation arrangements to any TDU that requires such 
arrangements.

Commission Conclusion

    NCMPA's concerns appear to be related to its existing power supply 
arrangements, not with new service under the pro forma tariff. These 
concerns are more appropriately addressed in a case-specific section 
206 complaint proceeding before the Commission.

Ohio Valley--Power to Uranium Enrichment Facility

    Ohio Valley asks the Commission to clarify that the orders do not 
apply to Ohio Valley so that Ohio Valley can continue to provide the 
lowest possible cost, and most reliable, service to the Piketon, Ohio 
uranium enrichment facility owned by the United States.<SUP>804 
Otherwise, Ohio Valley argues, compliance could result in increased 
costs to the United States and to the customers of the utilities 
participating in providing power to the enrichment facility. Ohio 
Valley seeks to avoid unnecessary interference with its ability to 
carry out its obligations under the existing agreements, but is 
amenable to reasonable and prudent use of its transmission system in 
accordance with sections 211 and 212.<SUP>805
---------------------------------------------------------------------------

    \804\ Ohio Valley states that the facility is now leased by the 
United States to the United States Enrichment Corporation.
    \805\ Dayton filed a motion to reject Ohio Valley's request for 
rehearing, arguing that it was really an application for waiver. 
(Dayton Motion to Reject).
---------------------------------------------------------------------------

Commission Conclusion

    Ohio Valley's rehearing request is essentially an application for 
waiver that is not properly addressed in this proceeding. By order 
issued July 2, 1996, we explained that because of the fact-specific 
nature of waiver requests the Commission will not address such requests 
in a generic rulemaking proceeding, but will require entities seeking 
waiver to submit separate, fact-specific requests that will be docketed 
in separate OA proceedings.<SUP>806 Subsequently, Ohio Valley filed a 
separate petition for waiver in Docket No. OA96-126-000 that 
effectively reiterated the arguments made in its rehearing request. The 
Commission will address Ohio Valley's fact-specific arguments in Docket 
No. OA96-126-000.
---------------------------------------------------------------------------

    \806\ Order Clarifying Order Nos. 888 and 889 Compliance 
Matters, 76 FERC para. 61,009 (1996).
---------------------------------------------------------------------------

Exchanges

    Several entities argue that exchanges should be permitted without a 
requirement that customers book capacity for each direction the power 
will flow and parties should not each have to pay the full reservation 
charge.<SUP>807 Because point-to-point customers can change receipt 
points without payment of additional charges, they argue that the same 
logic applies to exchanges.
---------------------------------------------------------------------------

    \807\ E.g., VT DPS, Valero, APPA.
---------------------------------------------------------------------------

Commission Conclusion

    An exchange between two utilities has traditionally been viewed as 
two separate transactions (two one-way services) from the transmitting 
utility's planning and reservation perspective and has been priced as 
two separate services. Consistent with this approach, the pro forma 
tariff only allows changes to points of receipt and delivery for point-
to-point service on a non-firm basis at no extra charge. Any changes to 
points of receipt and delivery on a firm basis must be submitted to the 
Commission as new applications. However, we note that comparability is 
achieved if the transmission provider charges itself and its 
transmission customers for point-to-point service on a consistent 
basis, whether that be separately for both directions or on a 
bidirectional basis.

Various Rate Matters

    VT DPS and Valero argue that rates ``should be based on a 
definition and quantification of a core of transmission function lines 
and substations for use in wholesale wheeling rather than on the basis 
of a rolled-in rate for the entire

[[Page 12435]]

transmission network.'' VT DPS states that ``[i]n order to insure 
against cross subsidization, the tariffs should provide for the 
imposition of a Local Transmission System Access Charge to recover the 
costs of the facilities used to provide service to customers in this 
category.'' (VT DPS at 23-24; Valero at 8-10).
    American Forest & Paper argues that

the Commission's proposal includes as part of the transmission 
revenue requirement amounts attributable to the utility's use of its 
own transmission system to effectuate off-system sales and revenues 
received from transmission customers taking service under existing 
contracts and tariffs but not under the new transmission tariffs. By 
failing to subtract such revenues from the revenue requirement used 
to determine rates for services rendered under the new tariffs, the 
utility effectively recovers these amounts twice: once from its off-
system sales and transmission customers not taking service under the 
new tariffs and a second time from its customers taking service 
under the proposed new tariffs.''<SUP>[808]
---------------------------------------------------------------------------

    \808\ American Forest & Paper at 24.
---------------------------------------------------------------------------

    American Forest & Paper asserts that to eliminate this double-
recovery, the Commission should adopt PacifiCorp's proposal in Docket 
No. ER95-1240. American Forest & Paper further declares that the 
Commission must demonstrate that the charges imposed on customers of 
network wheeling service are commensurate with the benefits that they 
receive.

Commission Conclusion

    We are not prepared to mandate in a generic proceeding such as this 
that all transmission rates must be established by function or that a 
specific pricing methodology should be used. Our rate policy, as set 
forth in the Transmission Pricing Policy Statement, is to encourage 
flexible and innovative rate approaches by the electric industry. 
Mandating a single methodology for the entire industry would certainly 
defeat that goal. While the Commission welcomes new and innovative 
proposals, we will not impose a generic change in this proceeding. As 
always, utilities are free to propose the use of a functional pricing 
method in their compliance filings or in any section 205 filing it may 
submit to the Commission.

Federal Government Contract Clauses

    ConEd asserts that the Commission must modify the pro forma tariff 
to include certain Federal government required anti-discrimination 
clauses. According to ConEd, these clauses require that all of Con 
Edison's transmission providers agree to be bound by certain provisions 
of the federal subcontractor regulations. ConEd suggests that the 
``Commission state that Con Edison and similarly-situated utilities be 
permitted to comply with the federal subcontracting requirements by 
inserting such clauses in their service agreements for transmission 
services.'' (ConEd at 17-18).

Commission Conclusion

    The Commission disagrees with ConEd's assertion that the Commission 
must modify the pro forma tariff to include certain Federal government 
anti-discrimination clauses. The Commission does not dispute that 
certain parties must comply with provisions of the federal 
subcontractor regulations for particular transactions that may involve 
the provision of transmission service. However, we do not agree that 
these provisions must be incorporated into the pro forma tariff. The 
contracting obligation raised by ConEd is independent of the pro forma 
tariff and more appropriately addressed in a separate contract between 
the parties to the purchase or the service agreements for transmission 
services. The Commission notes that this is apparently how the issue 
has been handled in the past by ConEd because its tariffs previously 
filed with the Commission (pre-NOPR) did not include such anti-
discrimination clauses.

V. Environmental Statement

Summary

    The Commission prepared an environmental impact statement (EIS) to 
evaluate the environmental consequences that could result from adopting 
the Rule. We did so largely in response to the claims of several 
commenters who charge that the Rule will have significant adverse 
environmental effects. As described in Order No. 888:

    Although a number of issues were raised, by far the most 
prominent concern arises from the theory that competitive market 
conditions created by the rule will provide an advantage to power 
suppliers who produce power from coal-fired facilities that are not 
subject to stringent controls on nitrogen oxides (NO<INF>X) 
emissions. Under this theory, these facilities, located primarily in 
the Midwest and South, will, as a result of the rule, generate more 
power and emit more NO<INF>X, which will contribute to ozone 
formation. The ozone could add to pollution both in those regions 
and more significantly in the Northeast, to which area such 
pollutants could be transported. Those who propound this theory 
argue that it is the responsibility of the Commission, using its 
authority under the Federal Power Act, to effect environmental 
controls that will mitigate what they predict will be significant 
increases in NO<INF>X emissions associated with this rule.<SUP>[809]

    \809\ FERC Stats. & Regs. at 31,860; mimeo at 657-58 (footnote 
omitted).
---------------------------------------------------------------------------

    The EIS recognizes that the electric industry will contribute to 
air emissions regardless of whether the Rule is adopted. The purpose of 
the EIS is to analyze to what extent the Rule is likely to affect those 
emissions.
    Many variables can influence the impacts of the Rule and the EIS 
uses a modeling framework that incorporates a range of assumptions 
about these variables. The most significant variable is likely to be 
the future prices of the two primary fuels used to generate 
electricity--coal and natural gas. Government and industry price 
forecasts were used to construct two alternative fuel price 
assumptions: (1) that the price of natural gas will increase relative 
to the price of coal; and (2) that the relative price of coal and 
natural gas will remain constant. These assumptions form the basis for 
two base cases that project the environmental impacts of developments 
in the electric industry without the Rule. The EIS then makes 
assumptions about the effects of the Rule to create three scenarios 
that project a range of possible results. It compares the environmental 
impacts projected in the scenarios with those projected in the base 
cases to determine the effect of the Rule.<SUP>810 The analysis set 
forth in the EIS demonstrates that the Rule will not in any significant 
respect affect overall trends in NO<INF>X emissions.
---------------------------------------------------------------------------

    \810\ The EIS also conducts sensitivity analyses of how 
projected air emissions might change if key assumptions in the 
analysis are changed. These analyses include two frozen efficiency 
reference cases which represent a world in which: (1) the Commission 
reverses current pro-competitive transmission policy (inconsistent 
with congressional mandates under EPAct); (2) states cease to adopt 
programs to improve industry efficiency; and (3) electric companies 
cease to improve operations or to enter into mutually beneficial 
transactions.
---------------------------------------------------------------------------

    Subsequent to the issuance of Order No. 888, the Environmental 
Protection Agency (EPA) conducted a review of the Commission's FEIS in 
which EPA employed alternative assumptions for a number of model 
inputs. In doing so, EPA stressed that ``[n]aturally there can be 
differences among reasonable analysts concerning the assumptions used 
in such an analysis'' and that ``EPA believes the assumptions used by 
the FERC and those used by EPA both lie within the reasonable range.'' 
<SUP>811 EPA has concluded that the Rule is unlikely to have any 
significant adverse environmental impact in the immediate

[[Page 12436]]

future, and that implementation of the Rule should go forward without 
delay. In reaching these conclusions, EPA concurred that the Commission 
conducted an adequate NEPA analysis of the environmental impacts of the 
Rule under a range of possible scenarios. EPA also agreed that the 
Commission made a reasonable choice of models with which to conduct the 
analysis and, as noted above, made assumptions for various factors 
input into the model that lie within the range of reasonable 
assumptions.
---------------------------------------------------------------------------

    \811\ Letter of May 22, 1996 from Mary Nichols, Assistant 
Administrator for Air and Radiation, EPA, to Kathleen McGinty, 
Chair, CEQ.
---------------------------------------------------------------------------

    EPA also concurred with the Commission that NO<INF>X emissions 
increases associated with the Rule, if any, should be addressed as part 
of a comprehensive NO<INF>X emissions control program developed by EPA 
and the states pursuant to the Clean Air Act. EPA committed to use its 
Clean Air Act authority to support successful completion of this 
program, and stated that it will establish a NO<INF>X cap-and-trade 
program through Federal Implementation Plans if some states are 
unwilling or unable to act in a timely manner.
    In a letter dated May 13, 1996, the EPA Administrator referred 
Order No. 888 to CEQ.<SUP>812 In doing so, EPA suggests that if the 
Ozone Transport Assessment Group (OTAG) and Clean Air Act processes 
fail to produce the necessary pollution limitations in a timely manner, 
EPA will call upon all other interested federal agencies to assist in 
solving the problem. EPA would ask the Commission to contribute by 
examining, through a Notice of Inquiry, possible strategies for 
mitigating NO<INF>X emissions increases associated with the Rule.
---------------------------------------------------------------------------

    \812\ Letter of May 13, 1996, from Carol Browner, Administrator, 
EPA to Kathleen McGinty, Chair, CEQ.
---------------------------------------------------------------------------

    The Commission subsequently responded by issuing an order stating 
that if EPA concludes that the OTAG process has not succeeded in 
meeting its objectives in a timely manner, the Commission would 
initiate a Notice of Inquiry to further examine what mitigation might 
be permissible and appropriate under the Federal Power Act. Such an 
inquiry would solicit public comment on how to assess appropriately the 
air pollution impacts attributable to the Rule, suitable ways in which 
to address such impacts, if any, and the scope of the Commission's 
authority to address such impacts. The Commission also stated that, 
under the extraordinary circumstances in which EPA would undertake a 
Federal Implementation Plan, the Commission would agree to initiate 
contemporaneously a rulemaking to propose possible mitigation that 
could be undertaken by the Commission under the FPA. Such a rulemaking 
would be undertaken on the basis of the Notice of Inquiry discussed 
above and would be appropriate only if environmental harm attributable 
to the Rule that warranted mitigation is demonstrated.<SUP>813 On June 
14, 1996, CEQ concluded that the Commission's order was fully 
responsive to EPA's concerns and requests and that the referral process 
and corresponding responses to the referral from the Commission and 
other agencies have successfully resolved the disagreements between EPA 
and the Commission.<SUP>814
---------------------------------------------------------------------------

    \813\ Order Responding to Referral to Council on Environmental 
Quality, 75 FERC para. 61,208 at 61,691-92 (1996).
    \814\ Letter of June 14, 1996 from Kathleen McGinty, Chair, CEQ, 
to Carol Browner, Administrator, EPA and Elizabeth Moler, Chair, 
FERC.
---------------------------------------------------------------------------

    As discussed below, EPA is currently taking steps to implement a 
comprehensive NO<INF>X emissions control program to ensure that 
emissions reductions are achieved to prevent significant transport of 
ozone pollution across state boundaries in the Eastern United States. 
OTAG is continuing to work in conjunction with EPA on this issue and 
intends to complete its process in the near future.
    Rehearing is sought on eight categories of issues relating to the 
Commission's analysis of environmental issues: selection of the 
appropriate no-action alternative; challenges to modeling assumptions; 
need for mitigation; emissions standards disparity; the short-term 
consequences of the Rule; cost benefit analysis; socioeconomic impacts; 
and compliance with the Coastal Zone Management Act. For the reasons 
discussed below, rehearing is denied.

A. The Appropriate No-Action Alternative

    The FEIS discusses several alternatives, including the alternative 
of instituting open access pursuant to section 211 of the FPA. The FEIS 
states in this regard that:

    Actions taken pursuant to section 211 and pursuant to sections 
203 and 205 in merger and market-rate cases, respectively, represent 
a case-by-case approach to establishing open access. Absent action 
on the proposed rule, the Commission would continue using these 
authorities to require utilities to file open access tariffs and 
provide case-specific service, as necessary or appropriate. In 
addition, sections 205 and 206 charge the Commission with ensuring 
that purely voluntary transmission tariffs are not unduly 
discriminatory. Thus, if the proposed rule were not adopted, the 
Commission would continue to require that voluntary tariffs be 
upgraded to offer the Commission's current standards for non-
discriminatory open access transmission services. The result of 
continuing the Commission's policies without the proposed rule is 
that the Commission would effectuate a more open transmission grid, 
but in a patchwork manner and at a slower pace.
    The case-by-case approach to achieving open access currently in 
use is slower and more costly, and thereby less desirable, than the 
generic approach set forth in the proposed rule. Thus, the no-action 
alternative is not a reasonable alternative to the proposed 
rule.<SUP>815
---------------------------------------------------------------------------

    \815\ FEIS at 2-1 and 2-2.
---------------------------------------------------------------------------

Rehearing Requests

    The PA Com contends that the FEIS does not adequately consider the 
alternative of instituting open access pursuant to section 211 of the 
FPA. It states that section 211 provides a means for wholesale power 
sellers and buyers to obtain transmission services necessary to compete 
in, or to reach competitive markets, and that the FEIS ignores the 
steady, if slow, progression to open access taking place under section 
211.

Commission Conclusion

    The FEIS notes that there are significant reasons for implementing 
open access through a rulemaking rather than the case-by-case approach 
of section 211. In the absence of a Commission rulemaking, the 
development of open access pursuant to section 211 would occur as 
potential transmission users file requests for such services and the 
Commission approves them as appropriate. Such proceedings are likely to 
be contested by competitors and the Commission would decide each 
application individually. Given the number of potential transmission 
users who are likely to file requests for such services, it is 
conceivable that this approach may require the Commission to decide a 
large number of such applications. <SUP>816 Thus, the case-by-case 
approach is likely to be much slower and more costly to implement than 
action by rule.
---------------------------------------------------------------------------

    \816\ To date, the Commission has issued six proposed orders and 
four final section 211 orders. Id. at 2-1.
---------------------------------------------------------------------------

    Case-by-case implementation of open access is also more likely to 
result in patchwork development as the policy evolves over time. It is 
important to develop uniform national standards to facilitate the move 
to open access. This approach adds certainty and facilitates 
development and implementation of open access in a way that would be 
difficult to achieve on a case-by-case basis. The development of 
national

[[Page 12437]]

standards is best done through a mechanism whereby all interested 
parties can participate in shaping the policy through notice and 
comment rulemaking. The piecemeal implementation of open access on a 
case-by-case basis over time, no matter how carefully conducted, is 
likely to result in inconsistencies and difficulty in application. 
Given the national nature of the electric grid and the developing open 
access market, case-by-case implementation is not practical nor 
desirable and will limit the anticipated benefits of open access.
    The PA Com does not specify how the Commission fails to adequately 
consider the alternative of instituting open access pursuant to section 
211. It is insufficient for a party to complain that an analysis is 
inadequate without providing specific support for its claim. As the 
court noted in Northside Sanitary Landfill, Inc. v. Thomas, 849 F.2d 
1516, 1519-20 (D.C. Cir. 1988), cert. denied, 489 U.S. 1078 (1989):

    In Vermont Yankee Nuclear Power Corp. v. Natural Resources 
Defense Council, Inc., 435 U.S. 519, 98 S.Ct. 1197, 55 L.Ed.2d 460 
(1978), then-Justice Rehnquist expressed the unanimous opinion of 
seven members of the Supreme Court that a party * * * has the burden 
of clarifying its position for the [agency]. Even though the 
[agency] has the statutory obligation to consider fully significant 
comments, ``it is still incumbent upon intervenors who wish to 
participate * * * to structure their participation so that it is 
meaningful, so that it alerts the agency to the intervenors' 
position and contentions.'' 435 U.S. at 553, 98 S.Ct. at 1216. 
Justice Rehnquist, then quoted with approval Judge Leventhal's 
remarks in Portland Cement, id., and concluded that administrative 
proceedings should not be a game or a forum to engage in unjustified 
obstructionism by making cryptic and obscure references to matters 
that ``ought to be'' considered and then, after failing to do more 
to bring the matter to the agency's attention, seeking to have that 
agency determination vacated on the ground that the agency failed to 
consider matters forcefully presented.''

Id., at 533-54, 98 S.Ct. at 1217.

    We also note that the PA Com's quarrel does not appear to be with 
the Commission's analysis of the section 211 alternative in any event, 
but rather with the underlying policy decision to implement open access 
through a rulemaking rather than more slowly on a case-by-case basis.
    The Administrative Procedure Act authorizes agencies to establish 
policies by rulemaking or on a case-by-case basis. Here, the Commission 
has properly exercised its discretion to establish open access by 
rulemaking rather than in individual proceedings. The PA Com does not 
contest this authority or the Commission's exercise of it. Rather, its 
complaint goes to the underlying policy choices guiding that decision. 
Disagreement with an agency's policy choice is not a proper basis for a 
NEPA-based challenge to agency action. As the Circuit Court of Appeals 
for the District of Columbia (D.C. Circuit) stated in Foundation on 
Economic Trends v. Lyng, 817 F.2d 882, 886 (D.C. Cir. 1987) (footnote 
omitted) (brackets in original):

NEPA was not intended to resolve fundamental policy disputes. As the 
Supreme Court recently admonished, ``[t]he political process, and 
not NEPA, provides the appropriate forum in which to air policy 
disagreements.'' Metropolitan Edison Co. v. People Against Nuclear 
Energy, 460 U.S. 766, 777, 103 S.Ct. 1556, 1563, 75 L.Ed.2d 534 
(1983) (citation omitted). A policy disagreement, at bottom, is the 
gravamen of appellants' complaint. In our view, ``[t]ime and 
resources are simply too limited for us to believe that Congress 
intended to extend NEPA as far as [appellant would take] it.'' Id. 
at 776, 103 S.Ct. at 1562. <SUP>[817]]
---------------------------------------------------------------------------

    \817\ See also Northwest Coalition for Alternatives to 
Pesticides v. Lyng, 844 F.2d 588, 591 (9th Cir. 1988).

    Contrary to the PA Com's assertion, and regardless of the basis for 
that assertion, the discussion of the section 211 alternative in the 
FEIS satisfies the requirements of NEPA. The Supreme Court has stated 
that ``[t]o make an impact statement something more than an exercise in 
frivolous boilerplate the concept of alternatives must be bounded by 
some notion of feasibility.'' <SUP>818 ``Central to evaluating 
practicable alternatives is the determination of a project's purpose.'' 
<SUP>819 ``The range of alternatives that must be considered in the EIS 
need not extend beyond those reasonably related to the purposes of the 
project.'' <SUP>820 The purpose of the Rule is to implement open access 
in order to remedy undue discrimination and to do so on a timely basis 
and in a uniform manner; the Commission has determined that case-by-
case implementation of open access will not satisfy that purpose.
---------------------------------------------------------------------------

    \818\ Vermont Yankee Nuclear Power Corp. v. Natural Resources 
Defense Council, Inc., 435 U.S. 519, 551 (1978); Laguna Greenbelt, 
Inc. v. U.S. Department of Transportation, 42 F.3d 517, 524 (9th 
Cir. 1994).
    \819\ National Wildlife Federation v. Whistler, 27 F.3d 1341, 
1345 (8th Cir. 1994).
    \820\ Laguna Greenbelt, supra, 42 F.2d at 524. In that case, 
involving construction of a tollroad, Laguna contended that the EIS 
ignored a smaller, four-lane alternative. The EIS addressed this 
proposal, explaining that it was rejected because a four lane 
highway would not meet the project's goal of reducing traffic 
congestion. The court found that the proposal was thus properly 
rejected as not reasonably related to the purposes of the project. 
Id. at 524-25.
---------------------------------------------------------------------------

    The PA Com has proffered no reasons why the examination in the FEIS 
of the section 211 alternative is insufficient. We conclude that the 
FEIS adequately considers the alternative of instituting open access 
pursuant to section 211. Rehearing on this issue is denied.

B. Challenges to Modeling Assumptions

    Several rehearing requests challenge the modeling assumptions used 
in the FEIS. These challenges are raised in support of the claim that 
the Commission's analysis understates the environmental impacts of the 
Rule. The most fundamental challenge is the PA Com's claim that 
computer modeling is insufficient to examine the impacts of the Rule. 
The PA Com and Joint Commenters suggest that the model fails to use the 
appropriate base case. Questions are also raised regarding specific 
assumptions used in the model.
    In discussing these issues below, we note that although EPA raised 
many similar points with respect to the Commission's modeling approach 
in comments on the DEIS, EPA ultimately concluded that ``the FERC has 
conducted an adequate analysis under the National Environmental Policy 
Act of the environmental impacts of the open access rule under a range 
of possible scenarios'' and that ``[t]he FERC made a reasonable choice 
of models (CEUM) and made assumptions for various factors input into 
the model that lie within the range of reasonable assumptions.'' EPA 
also notes that the Commission performed the specific additional 
analyses that were requested in comments on the draft EIS.
    As EPA points out, ``[n]aturally, there can be differences among 
reasonable analysts concerning the assumptions used in such an 
analysis.'' EPA then reiterates that it believes that assumptions used 
by the Commission ``lie within the reasonable range.'' It concludes 
that ``the FEIS provides a credible basis for understanding the 
possible environmental impacts of the open access rule.''
1. Appropriate Base Case
    Selection of the appropriate base case was contested in the DEIS on 
grounds similar to those presented here. Certain commenters argued that 
the Commission should compare the impacts of the Rule to a no-action 
alternative that assumes that the Commission abandons all open access 
policies, not just the Rule. Some commenters went even further, 
suggesting that the Commission compare emission levels projected to 
result from the Rule against a frozen efficiency case in which other 
major

[[Page 12438]]

factors--factors that would increase industry efficiency independent of 
the Rule--do not occur. Such factors include adoption of pro-
competitive state polices and actions by utilities to undertake 
mutually beneficial voluntary transactions that do not require the use 
of open access tariffs mandated under the Rule. Commenters who 
advocated either a different no-action alternative or the frozen 
efficiency case posited that studies using those assumptions would show 
that the Rule will cause significantly greater NO<INF>X emissions than 
those shown in the DEIS. We concluded in Order No. 888 that:

[S]taff has selected the appropriate ``no-action'' alternative. An 
alternative that requires the Commission to reverse all its other 
open access policies is simply not a ``no-action'' alternative. To 
the contrary, it would require decisive action running counter to 
the direction from the Congress in the Energy Policy Act and the 
needs of the marketplace and electricity consumers.
    However, to ensure that the effects of the rule were analyzed 
fully, the FEIS did study a reference case based on the ``frozen 
efficiency'' case * * * Although, as described below, we believe 
this case to be highly unlikely, the results show that, even under 
this scenario, the impacts of the rule are not great and do not vary 
significantly from those projected by staff under the other 
assumptions. <SUP>[821]]
---------------------------------------------------------------------------

    \821\ FERC Stats. & Regs. at 31,863; mimeo at 665-66 (footnote 
omitted).
---------------------------------------------------------------------------

Rehearing Requests

    Pennsylvania PUC. The PA Com asserts that the Commission did not 
compare emissions levels associated with the Rule against the 
appropriate base case. It claims that the Commission should have used 
continued case-by-case evolution of open access and increased wholesale 
competition under FPA sections 211 and 212 as the base case instead of 
generic, simultaneous, nationwide open access as mandated by Order No. 
888. Put differently, the PA Com claims that the appropriate base case 
is the evolution of competition and open access without the 
intervention of Order No. 888. The PA Com concludes that by using the 
improper base case the FEIS ignores evidence of significant NO<INF>X 
increases resulting from the Rule, which affects the ability of 
Pennsylvania to meet the mandates of the Clean Air Act.
    Joint Commenters. The Joint Commenters maintain that the FEIS uses 
an inappropriate no-action alternative as a basis for analysis. 
<SUP>822 The gist of its argument is that the Commission must 
acknowledge the policy initiative of which it contends Order No. 888 is 
only one part. It claims that the Commission ignores the fact that, 
whether competition is pursued through Order No. 888 or on a case-by-
case basis, implementation of open access is a major programmatic 
policy choice the environmental impacts of which must be addressed. It 
contends that by using case-by-case implementation as the no-action 
alternative, the Commission effectively defines away most of the 
impacts of the Rule.
---------------------------------------------------------------------------

    \822\ Although cast as use of an inappropriate ``no action 
alternative'', the Joint Commenters' point goes to the 
appropriateness of the base case used in the analysis.
---------------------------------------------------------------------------

    In short, the Joint Commenters claim that by defining the no-action 
alternative as implementation of the open access program over a longer 
period of time through case-by-case action, the Commission did not 
fully examine the potential impacts of Order No. 888. It states that if 
the effects of Order No. 888 are defined to include only those that 
result from the timing difference between implementation of open access 
through case-by-case decisions and open access pursuant to a generic 
rule, it is virtually a foregone conclusion that most of the 
potentially adverse environmental effects of the Commission's open 
access policies will not be identified.
    The Joint Commenters concur that the frozen efficiency case 
analyzed in the FEIS is a proper starting place for an acceptable NEPA 
review. It faults the discussion of the frozen efficiency case, 
however, as failing to provide important information needed to allow 
parties to evaluate the analysis. The Joint Commenters complain that 
the analysis does not include the model outputs which demonstrate the 
most severe environmental effects; this, they claim, makes it 
impossible to verify the results or analyze the factors contributing to 
the effects shown.
    The Joint Commenters state that in addition to omitting the 
modeling outputs for the most environmentally relevant cases, the FEIS 
does not contain air quality modeling of the scenarios that show the 
greatest emissions increases. It claims that the Urban Airshed Model 
(UAM-V) examines only the incremental impacts of the Competition-
Favors-Coal Scenario as compared with the High-Price-Differential Base 
Case, the same analysis presented in the DEIS. The Joint Commenters 
stress that EPA in its comments on the DEIS noted that the results 
shown for this case (an emissions decrease) is illogical and should be 
explained. It states that without modeling the emissions changes 
associated with the Competition-Favors-Coal Scenario over the frozen 
efficiency base case, the FEIS provides no indication of the 
seriousness of the environmental harm from potential emissions 
increases caused by FERC's initiatives. The Joint Commenters also claim 
that the expanded transmission analysis used in the FEIS is unduly 
conservative.

Commission Conclusion

    The Commission continues to believe that the base cases and 
scenarios used in the DEIS are most appropriate for studying the 
effects of the Rule. Nonetheless, to ensure that the effects of the 
Rule were analyzed fully, the FEIS also examined a frozen efficiency 
case that uses a combination of assumptions most likely to show 
significant increases in emissions.
    We did this despite our belief that it is inaccurate to attribute 
all efficiency improvements in the industry to Order No. 888 or even to 
federal actions of all kinds. In fact, as noted in the FEIS, the frozen 
efficiency case is far more extreme in its assumptions than would be 
reasonable for a no-further-Commission-action case because it presumes 
that industry and state regulators also cease all changes toward a more 
competitive industry. However, the frozen efficiency case is useful as 
a sensitivity analysis because it reflects an extreme bound on any 
separate no-further-Commission-action case. <SUP>823 A fortiori the 
impact actually to be expected from the Rule must be less than that 
determined using the frozen efficiency case.
---------------------------------------------------------------------------

    \823\ This analysis is described as a sensitivity analysis 
because it examines how projected air emissions might change if key 
assumptions in the analysis are altered.
---------------------------------------------------------------------------

    We believe that the frozen efficiency analysis is highly 
implausible because its represents a world in which: (1) the Commission 
reverses current pro-competitive transmission policies (inconsistent 
with congressional mandates under EPAct); (2) states cease to adopt 
programs to improve industry efficiency; and (3) electric companies 
cease to improve operation or to enter into mutually beneficial 
transactions.
    The Joint Commenters agree that the frozen efficiency analysis 
constitutes a valid NEPA review. That issue, therefore, is not in 
dispute. It objects that the FEIS does not include the model outputs 
for the sensitivity cases which demonstrate the most severe 
environmental effects, and that it is therefore impossible to verify 
the results or analyze the factors contributing to the effects shown.
    The Joint Commenters' assertion is incorrect. Appendix K of the 
FEIS sets forth tables demonstrating the results of

[[Page 12439]]

the model runs for the sensitivity analysis. These tables provide 
adequate documentation to analyze and verify the conclusions reached in 
the FEIS. We note also that the Joint Commenters have not requested 
specific model outputs that it claims are lacking. The Commission will 
make available information used in the study that Joint Commenters or 
anyone else identifies as not being provided.
    As to the claim raised by the PA Com, it appears to be mistaken 
regarding the base case actually used in the FEIS. Contrary to what the 
PA Com states, the base cases do include continuing case-by-case 
actions under section 211 and the Commission's open access policy.
2. Challenge to the Use of Computer Modeling
    The Commission's intent to use computer modeling in the 
identification and evaluation of the impacts of the Rule has been clear 
since the Commission decided to prepare an EIS. The DEIS and FEIS 
explain the computer modeling techniques used in the analysis in great 
detail.
    For example, the DEIS and FEIS explain that the Coal and Electric 
Utilities Model (CEUM) was selected for the analysis because it is the 
best tested, most widely used national-level model available. <SUP>824 
CEUM is a forecasting model that incorporates virtually all coal and 
electric utility market activities--ranging from mining, 
transportation, and blending of coal to power plant and system 
dispatching, transmission, and new capacity construction. It also 
examines the impact of changes in factors such as plant availabilities, 
heat rates, planning reserve margins, and transmission costs. CEUM has 
been used extensively by, among others, EPA and DOE.
---------------------------------------------------------------------------

    \824\ DEIS at 3-2 through 3-5; FEIS at 3-2 through 3-5.
---------------------------------------------------------------------------

    CEUM models the contiguous United States as 45 separate demand 
regions. It possesses a supply component which models key coal supply 
regions and coal transportation networks in great detail. It also 
incorporates constraints on long-term coal supplies, power plant 
emission limitations, national emission caps (e.g., acid rain 
requirements of Title IV of the Clean Air Act Amendments of 1990), coal 
transportation capacity, electric transmission capacity, and power 
plant construction plans.
    The DEIS and FEIS explain that to analyze the Rule, assumptions as 
to factors such as electricity demand growth rates, oil and gas prices, 
and planning reserve margins were developed and incorporated into the 
model. Factors such as existing patterns of transmission capacity and 
costs were also analyzed and incorporated into the model.
    Once the necessary information and assumptions were incorporated 
into CEUM, model runs were conducted to ensure that the projections 
closely match actual experience for a selected year, in this case 1993. 
These runs used the information prepared for the base cases together 
with other inputs (e.g., electricity demand) for the historical year. 
The purpose of this calibration process was to ensure that the model 
replicates historical experience. After the model was calibrated, it 
was run for each of the base cases, and then for each of the Rule 
scenarios for selected time periods.
    To examine the impact of the Rule on regional attainment of ozone 
standards, additional air quality modeling was conducted using the UAM-
V. UAM-V is a three-dimensional photochemical grid model that simulates 
the physical and chemical processes in the atmosphere that affect 
pollutant concentrations. It tracks emissions both geographically 
according to preset weather patterns and chemically over time. The UAM-
V was used to create detailed air quality analyses for cases that might 
potentially create additional impacts from NO<INF>X transport and ozone 
in the Northeast.

Rehearing Requests

    The PA Com challenges the ability of computer modeling to simulate 
the effects of the Rule. It states that computer modeling is an attempt 
to reflect an approximation of reality that uses systems of linear 
equations, and that the airborne transport of pollutants in the 
atmosphere and the North American electric transmission grid are 
extremely large, complex nonlinear systems.<SUP>825
---------------------------------------------------------------------------

    \825\ The PUC appears to base its rehearing comments on the 
DEIS; the points it asserts on rehearing ignore extensive responses 
to these comments in the FEIS. For example, the FEIS responds to the 
following specific points that are now raised by the PUC on 
rehearing: Impact of the rule on Pennsylvania coal production (FEIS 
at J-22); impact on reliability (FEIS at J-26); impact on stranded 
benefits (FEIS at J-30); impact of assumed increased volume of 
transmission transactions (FEIS at J-39); claim that the analysis 
must consider impact of Group II boiler rule and Phase III of the 
MOU (FEIS at J-49); claim that FEIS makes conclusory statements 
(FEIS at J-60); claim that heat rate assumptions are optimistic 
(FEIS at J-63); claim that transmission usage prices are circular 
(FEIS at J-65); claim that availabilities are speculative (FEIS at 
J-67); claim that reserve margins are unlikely to fall as far as the 
FEIS assumes (FEIS at J-68); concerns about choice of linear 
modeling (FEIS at J-73); concerns about differing emission standards 
in Pennsylvania and West Virginia (FEIS at J-92); claim that the 
Rule is inconsistent with Title I of the Clean Air Act (FEIS at J-
97).
---------------------------------------------------------------------------

    The PA Com's challenge to the use of computer modeling also turns 
on the observation that models produce results that are dependent on 
the inputs and assumptions used in the models. The specific challenges 
to the inputs and assumptions used in the model are discussed 
separately below.

Commission Conclusion

    We note first that computer models are the only available means of 
analysis that incorporate the range of factors that influence 
engineering and economic choices in the electric power industry, and 
the atmospheric chemistry and weather patterns that influence 
downstream air quality. We are mindful of the limitations of models, 
but the alternative of using no model at all--and hence making no 
analytic attempt to capture the complex economic and environmental 
factors--did not appear reasonable.
    The PA Com does not explain how the Commission should otherwise 
simulate the effects of the Rule. Computer modeling may not be a 
perfect tool, but it is the best existing mode of analysis for this 
type of effort. The PA Com cannot merely assert that such modeling is 
inadequate. As the court noted in a similar context in City of Los 
Angeles v. National Highway Traffic Safety Administration, 912 F.2d 
478, 488 (D.C. Cir. 1990), overruled in part on other grounds, Florida 
Audubon Society v. Bentsen, 94 F.3d 658 (D.C. Cir. 1996):

    Petitioners call for more ``analysis,'' but do not specify what 
they see as lacking or how ``analysis'' could supply the want. At 
some point--here after a seemingly full treatment--the agency must 
make a judgment. We discern no more from petitioners' argument than 
that they disagree with that judgment. Even were we to share their 
view of the matter, that would not be a sufficient basis for 
overturning the agency's decision.

Quoting Portland Cement Ass'n v. Ruckelshaus, 486 F.2d 375, 394 (D.C. 
Cir. 1973), cert. denied sub nom. Portland Cement Ass'n v. 
Administrator, EPA, 417 U.S. 921, 94 S.Ct. 2628, 41 L.Ed.2d 226 (1974), 
the court in Northside Sanitary Landfill, Inc. v. Thomas, 849 F.2d 
1516, 1519 (D.C. Cir. 1988), cert. denied, 489 U.S. 1078 (1989), stated 
in like manner that:

    [C]omments must be significant enough to step over a threshold 
requirement of materiality before any lack of agency response or 
consideration becomes of concern. The comment cannot merely state 
that a particular mistake was made * * *; it must show why the 
mistake was of possible

[[Page 12440]]

significance in the results [the agency reaches]. (Emphasis in 
original).

    The FEIS explains the Commission's conclusion that the 
environmental analysis of Order No. 888 is best conducted using the 
CEUM and UAM-V computer models. The PA Com cannot merely state that the 
use of such models is inappropriate. It must explain why this is so and 
what alternative method of analysis should be used. This it has not 
done. The request for rehearing is denied.
3. Transmission Assumptions
    The FEIS recognizes the interdependence of interregional electric 
transmission transactions; accordingly, non-simultaneous interregional 
transfer capabilities estimated by the North American Electricity 
Reliability Council (NERC) were reduced for use in the model (see FEIS 
section 3.4.2). The analysis also considers the impact of the Rule on 
interregional transfers (see FEIS Tables 5-13 and 5-14), and the impact 
of changes in transmission capacity through sensitivity 
analysis.<SUP>826
---------------------------------------------------------------------------

    \826\ FEIS at 3-8 through 3-11.
---------------------------------------------------------------------------

Rehearing Requests

    The PA Com asserts that transmission usage in the FEIS is based on 
assumptions which are indeterminate to some degree. It states that 
historical interregional power transfers are used to estimate future 
transmission capabilities and capacity, and that while historical 
interregional electric transmission transactions have been large and 
complex, under the Rule the level of transactions will increase 
enormously. The PA Com claims that almost every time a new major 
interregional electric transmission transaction has occurred, there 
have been unpredictable flows of electricity in other regions that 
might be a thousand miles away. It concludes that relatively small 
changes in transmission flows can and have produced large harmonic 
transients and instabilities on the power grid.
    The PA Com also contends that the relationship between the 
transmission usage price and the price of transmission service is 
unclear. It states that the development of the usage price seems 
circular, at least in part. It notes that model inputs were changed 
until the usage price coincided with an estimate of historical costs. 
The PA Com requests clarification of the development of the usage price 
assumption.

Commission Conclusion

    The PA Com does not appear to understand the way the transmission 
usage price functioned in the analysis.<SUP>827 As explained in the 
FEIS, the CEUM model is annual and regional: it models a single year at 
a time using regions approximately the size of a state or large regions 
within a state.<SUP>828 Transmission in the model is represented as 
movement of power from one region to another. The model attempts to 
satisfy the demand for electricity at lowest cost--if there were no 
limitations on the movement of power from one region to another, the 
model would always generate power at the cheapest source and move that 
power to meet the demand. This result would clearly be unrealistic, 
since sources of power are limited in their ability to reach demand by 
limitations in the intervening transmission network. The transmission 
network in CEUM is represented primarily by the limitations that the 
transmission grid places on the ability of power to move freely to meet 
demand.
---------------------------------------------------------------------------

    \827\ As explained in the FEIS at 3-13 through 3-15 and as 
discussed below, the movement of power from low cost sources is 
limited not only by the physical constraints of the transmission 
system, but also by institutional impediments such as lack of access 
to needed transmission. As a result, in a model like that used in 
the EIS, where flows are based on minimizing costs subject to 
physical constraints, the model will typically overestimate the 
amount of power flowing from low-cost sources of generation. The 
Commission chose to address this by developing a ``usage price'' to 
raise the variable cost to simulate the effect of observed barriers 
to power flows between regions. The usage price is a proxy for 
transmission barriers, not an attempt to estimate or model an actual 
transmission price. The usage price was calibrated to produce actual 
historical flows of electricity, not costs of transmission. As such 
it has almost no relationship with actual transmission prices.
    \828\ Id.
---------------------------------------------------------------------------

    To use CEUM to provide a reasonable representation of transmission 
requires balancing the different ways in which the transmission system 
imposes limits on the movement of power. Flows on links between regions 
are limited by three general parameters in the model: losses, variable 
costs, and constraints on the quantity of capacity or energy that can 
be transferred. Losses are generally small, and are typically kept 
fixed from one model run to the next. Simulating transmission limits is 
largely a matter of balancing variable costs and quantity limits. True 
variable costs are usually assumed to be small, reflecting the low 
variable cost of operating the transmission system. Basic quantity 
limits are usually developed from NERC sources or other studies of the 
limits imposed by the physical operation of the transmission system.
    However, such limits do not always provide an adequate picture of 
current patterns of generation and transmission in the electric utility 
system. Movement of power from low cost sources is limited not only by 
the physical constraints of the transmission system, but also by 
institutional impediments such as lack of access to needed 
transmission. As a result, in a model like CEUM, where flows are based 
on minimizing costs subject to physical constraints, the amount of 
power flowing from lost-cost sources of generation is typically 
overestimated.
    The FEIS explains that there are two primary ways to address this 
difficulty when calibrating the model to represent historical power 
flows. One is to impose further limits on the quantity of power 
transferred within the model. The other is to raise the variable cost 
to simulate the effect of observed barriers to power flows between 
regions. The second approach was used by developing a ``usage price'' 
to raise the variable cost barriers in CEUM and supplement basic 
quantity limits derived from NERC estimates. This approach was taken 
because of its nexus to the primary effect of the Rule on transmission 
activities. The primary effect of the Rule on transmission will be to 
increase the ability of transmission users to gain access to 
transmission service and to permit users to develop flexible ways for 
buyers and sellers to use the transmission system efficiently. The 
primary effect is thus to remove institutional barriers to the use of 
the transmission system--in effect to reduce the transaction costs, or 
usage price, faced by those seeking access to transmission. Thus, the 
model was calibrated by selecting an initial set of usage prices and 
adjusting those prices until the model provided an accurate 
representation of historical generation and transmission patterns.
    Usage prices (in mills per kWh) were developed by running CEUM for 
a historical period (1993). Starting from initial estimates of usage 
prices between CEUM regions, the model was run using historical inputs 
for 1993; the outputs from these runs were compared with the historical 
pattern of generation and transmission for that year. Usage prices were 
then adjusted until the pattern projected by the model was consistent 
with the observed historical pattern. The final adjusted prices were 
then used as the current usage prices.
    Two rules were used to set the initial usage price estimates:

    (1) For closely coordinated (i.e., tight) pools, no separate 
usage price was assumed. This is consistent with the principle 
embodied in many pools that transmission

[[Page 12441]]

assets are to be treated as one system and used to minimize variable 
costs. Any allocation of the cost of service associated with 
transmission assets is typically treated as a fixed cost.
    (2) Separate transmission costs are commonly applied in loosely 
configured pools. In many cases, these separate costs are derived on 
a MW-mile basis. Because the number of systems that have to be 
traversed within a loosely configured pool is generally small, the 
transmission usage price for areas with loosely configured pools 
were set to a small initial value (1 to 2 mills/kWh). Transmission 
across NERC regions may require traversing many utility systems, and 
for modeling purposes a charge of about 3 mills/kWh was assumed.

    Applying this method required several runs of CEUM. Usage price 
changes were typically downward in areas where the initial prices were 
set at 3 mills per kWh, and prices after adjustment remained within the 
range of the initial usage prices. As a result, estimates of the 
current usage price varied from region to region after calibration, but 
generally fell within the range of 1 to 3 mills per kWh.
    Thus, the concerns expressed by the PA Com were either considered 
in the FEIS, or are based on a misunderstanding of the method used.
4. Plant Availabilities and Heat Rates
    The FEIS explains that power plant availability is the percentage 
of time that a generating unit is available to provide electricity to 
the grid, and that availability estimates for coal plants have an 
important effect on projected base case emissions because those 
estimates determine the amount of future generation expected from 
existing power plants.<SUP>829
---------------------------------------------------------------------------

    \829\ Id. at 3-18.
---------------------------------------------------------------------------

    The base cases assume that average fossil-fuel plant availability 
rises to 85 percent by 2005 and then remains constant through 2010. 
This assumption reflects continuing efforts by utilities to improve 
plant availability. Between 1984 and 1993, coal plant availability 
increased five percent to nearly 81 percent. This trend is projected to 
continue through 2005 as electric generators respond to competitive 
pressures and opportunities extant without the Rule.
    The FEIS explains that in the Competition-Favors-Coal Scenario, 
plant availabilities are assumed to reach 90 percent (as opposed to 85 
percent in the base cases and other Rule scenarios) because competition 
is projected to lead to greater operational efficiency in generation 
markets. It notes that some older coal plants are not likely to reach 
this level without substantial capital investment. However, since 90 
percent availability is achievable for many plants, this figure was 
selected as an upper bound to illustrate how much existing plants may 
be able to run if generation owners focus on meeting competition 
through greater use of coal plants.
    The FEIS also explains that the base cases assume some 
deterioration in heat rates between life extension programs. In the 
Competition-Favors-Coal Scenario, existing generating plants are 
assumed to be better maintained so that there is no deterioration of 
heat rates between life extension programs. Except in the Competition-
Favors-Gas Scenario, it is assumed that new combined cycle natural gas 
plants sustain existing heat rates (rather than improving as the next 
generation of gas technology comes on line). These assumptions reflect 
the fact that industry has put more effort into making better use of 
existing (disproportionately coal) plants rather than into improving 
the performance of new (almost entirely gas) plants.

Rehearing Requests

    The PA Com challenges the plant availability assumptions used in 
the FEIS. It notes that the analysis assumes that generation plant 
availability will rise to 85 percent and that the Competition-Favors-
Coal Scenario assumes that generation plant availability will rise to 
90 percent by the year 2005. The PA Com states that although historical 
trends indicate that plant availability might increase, in reality as 
availability goes up it becomes increasingly difficult to obtain 
further improvements.
    The PA Com contends that increasing availability to 85 percent 
would be surprising; an increase to 90 percent would be astonishing. It 
states that such increases would require a number of simultaneous 
technical advances, the likelihood of which are speculative. The PA Com 
argues that utilities in competition with each other may be less 
willing to fund and participate in cooperative research that leads to 
technical advances. The PA Com notes that maintenance staffs are being 
reduced as a result of cost reduction programs and that plant 
availability might decline as maintenance is deferred.
    The PA Com also contends that the assumption in the Competition-
Favors-Coal Scenario that heat rates do not degrade (go up) over time 
may be optimistic. It concedes that technological advances have 
produced dramatic improvements in heat rates, but states that it is 
unclear if this improvement is sufficient to overcome losses caused by 
backfitting emission control equipment. The PA Com notes that coal-
fired generating stations in Pennsylvania have been required to install 
emission control equipment and that efficiency has been reduced in some 
cases, degrading the heat rate. It states that some coal stations have 
installed sulfur dioxide (SO<INF>2) scrubbers which can reduce 
efficiency by five percent, and that other stations may be required to 
install selective catalytic reduction systems for NO<INF>x or SO<INF>2 
scrubbers.
    The PA Com contends that an additional limit on heat rate 
improvements is the age of generating stations and the fact that heat 
rates decline as stations age. It posits that this decline may be 
greater than the improvements that can be gained through technological 
advances.

Commission Conclusion

    The PA Com's argument fails to consider the discussion of this 
issue in the FEIS.<SUP>830 Briefly, higher availabilities for coal 
plants were assumed in order to provide a scenario that was extremely 
favorable to the use of coal in existing facilities and hence a 
scenario that was most likely to have a larger environmental impact. 
The fact that some coal plants are able to maintain 90 percent 
availability is sufficient grounds for considering such a case, 
especially where the purpose of the assumption is to establish a 
reasonable range of potential environmental outcomes from the Rule.
---------------------------------------------------------------------------

    \830\ Id. at J-63 and J-67.
---------------------------------------------------------------------------

    With regard to the heat rate assumptions, the PA Com does not 
appear to understand how the assumptions functioned in the analysis. 
First, the factors it mentions (e.g., efficiency reductions resulting 
from the addition of scrubber technology) are already considered in the 
CEUM model. Second, the CEUM does assume that heat rates degrade over 
time in the base cases. The assumption that they do not degrade in the 
Competition-Favors-Coal Scenario was made to simulate the relative 
improvement that might be achieved through potential effects of the 
Rule when competition is favorable to coal. As with certain other 
modeling assumptions challenged by the PA Com on rehearing, the heat 
rate assumptions used by the Commission are more conservative than 
those urged by the PA Com and thus demonstrate greater impacts from the 
Rule than would be the case using the assumptions urged by the PA Com.

[[Page 12442]]

5. Reserve Margins
    The FEIS discusses the assumptions regarding planning reserve 
margins and their use in the model.<SUP>831 It states that planning 
reserve margins influence the amount of new capacity built and the mix 
of gas versus coal fired generation projected in CEUM. In particular, 
lower reserve margins tend to result in the construction of less 
capacity (typically, fewer gas-fired turbines and combined cycle units) 
and a somewhat greater utilization of existing coal units.
---------------------------------------------------------------------------

    \831\ Id. at 3-16 and 3-17. Table 3-4 is found on page 3-17.
---------------------------------------------------------------------------

    Generally, individual utilities set their reserve margins to comply 
with a technical standard established by the NERC sub-region. 
Typically, the NERC sub-region might determine that a one day in 10 
years loss of load probability (LOLP) is the appropriate standard. 
Individual utilities within the sub-region would determine their 
reserve planning margin to be consistent with this standard after 
accounting for tie capabilities. NERC sub-regional studies are 
performed periodically to determine whether the reliability standard is 
being satisfied for the planning horizon given planned capacity 
additions. The tie capability between the sub-region and other regions 
is accounted for in reliability studies at the NERC sub-regional level.
    The FEIS notes that in recent years, reserve margins typically have 
been revised downwards, although the planning standard itself (most 
commonly the one day in 10 years LOLP) has not been changed. Three 
reasons support the downward revision in reserve margins: (1) An 
expected improvement in unit availability; (2) anticipated shifts in 
utility load shape towards a lower load factor; and (3) an increase in 
the number of generating units.
    FEIS Table 3-4 summarizes the reserve criteria and associated 
planning reserve margins that have been derived from the most recent 
annual planning documents prepared by the reliability councils. It 
states that a review of current planning documents shows that utilities 
expect planning reserve margins to decline over time. One factor 
identified as contributing to this decline is the expectation that 
availability will improve appreciably as utilities are subject to 
performance-based regulation and experience greater competition.
    Additionally, some utilities have revised their planning reserve 
margins to account for ties in other regions. In some cases, utilities 
have updated their planning reserve margin calculation to reflect 
current estimates of customer willingness to pay for increase 
reliability.
    Based upon a review of utility expectations, the FEIS concludes 
that an appropriate base case assumption is for planning reserve 
margins to decline by 2005 to the lower end of the applicable ranges 
set forth in FEIS Table 3-4.

Rehearing Requests

    The PA Com challenges the reserve margin assumptions used in the 
model. It asserts that the assumption that reserve margins will fall to 
fifteen percent by 2000 and (in one scenario) to thirteen percent by 
2005 is based in part upon the assumption of increased generation plant 
availability across the board. The PA Com notes that this increase in 
availability might not occur. It states that as wholesale transactions 
increase under open access, some, but not most, utilities will be able 
to reduce reserve margins and still maintain reliability. The PA Com 
asserts that many utilities cannot reduce reserve margins because 
available transmission capacity between regions is already being 
utilized to the maximum extent possible. It concludes that reserve 
margins for certain individual utilities could decline, but this alone 
would not reduce required reserve margins for all utilities to the 
levels that are assumed in the model.

Commission Conclusion

    The reserve margins used in the base cases were set using current 
utility plans and trends in the industry. Reserve margins for the 
competition scenarios were set slightly lower, reflecting the potential 
for decline in a more open competitive environment. The PA Com 
acknowledges the potential decline, but claims that not all utilities 
will be able to reduce reserve margins to the levels assumed. However, 
the FEIS addresses such differences by using different regional 
assumptions about reserve margins and different reserve margins in each 
region. The PA Com's concern is therefore without basis.
6. Northeast MOU
    The FEIS assumes that power plants in the Northeast Ozone Transport 
Region (OTR) will comply with Phase II of the Northeast Memorandum of 
Understanding (MOU). The MOU establishes NO<INF>X tonnage limits during 
the five-month ozone season (May-September) for electric generating and 
large industrial services and allows for emissions trading.<SUP>832 The 
FEIS states that compliance with Phase III of the MOU was not assumed 
since its implementation is optional, depending on final attainment 
status with regard to Clean Air Act requirements.
---------------------------------------------------------------------------

    \832\ Id. at 3-25.
---------------------------------------------------------------------------

Rehearing Requests

    The PA Com states that the base cases and scenarios assume that no 
NO<INF>X controls will be required for Title IV group II boilers, that 
phase II of the MOU will be implemented, and that no additional 
requirements will be imposed. The PA Com contends that phase III of the 
MOU might be implemented, and that if this occurs and upwind generation 
is not required to control ozone precursors, cleaner generation in the 
Northeast may be displaced by increased generation from outside the 
OTR.

Commission Conclusion

    In essence, the PA Com appears to be raising an emissions disparity 
argument rather than posing a challenge to the modeling assumptions 
used in the FEIS. The emissions disparity argument is addressed below.
7. Natural Gas Prices
    Average wellhead natural gas prices for the High-Price-Differential 
Base Case were based on a recent forecast of natural gas acquisition 
prices by Wharton Econometric Forecasting Associates (WEFA).<SUP>833 
This forecast projected at that time that natural gas prices would 
increase in real terms (1994 dollars) to $1.83 per MMBtu by 2000, and 
rise to $2.42 per MMBtu by 2010. The forecast was selected as 
representative of a number of natural gas price forecasts that were 
made during that time.
---------------------------------------------------------------------------

    \833\ Id. at 3-5 through 3-8.
---------------------------------------------------------------------------

    CEUM requires delivered, not wellhead or acquisition, prices as an 
input. Delivered natural gas prices for each Census region were derived 
from the weighted average transportation mark-ups reported by the 
Energy Information Administration (EIA) in Natural Gas Monthly for each 
Census region. The Natural Gas Monthly provides a consistent historical 
series of wellhead and delivered prices for calculating historical 
transportation margins. These margins were assumed to remain constant 
throughout the forecast period.
    In the Constant-Price-Differential Base Case, delivered gas prices 
were assumed to equal current delivered spot prices in each region. To 
maintain a constant gas price relative to coal, these prices were 
assumed to decline from current levels

[[Page 12443]]

at the same rate as coal prices decline in CEUM.<SUP>834
---------------------------------------------------------------------------

    \834\ Id. at 3-7 through 3-8.
---------------------------------------------------------------------------

Rehearing Requests

    The Joint Commenters assert that the fuel-price assumptions used in 
the model unduly favor the use of natural gas as a fuel and appear to 
understate adverse effects.
    In particular, the Joint Commenters claim that the two alternative 
fuel-price cases use the same coal price assumptions. It states that 
the Competition-Favors-Coal Scenario is supposed to demonstrate the 
effects of economic assumptions that favor coal, but that this case 
actually uses price assumptions that reflect the lowest natural gas 
price of the projections cited in the FEIS. It states that the FEIS 
should have used projections less favorable to natural gas: for 
example, $2.51 per MMBtu in 2000 (Gas Research Institute) and $3.37 per 
MMBtu in 2010 (Energy Information Administration). Put differently, a 
more appropriate Competition-Favors-Coal Scenario would have used the 
projected highest reasonable natural gas prices relied on in the FEIS.
    The Joint Commenters then claim that the Constant-Price-
Differential Base Case is based on gas price assumptions that are far 
below the projected prices cited in the FEIS.<SUP>835 According to the 
Joint Commenters, this case assumes natural gas prices of $1.67 per 
MMBtu in 2000 and $1.57 per MMBtu in 2010. It asserts that these 
estimates are approximately 10 and 54 percent lower in years 2005 and 
2010, respectively, than the lowest forecasts cited. A more appropriate 
Competition-Favors-Gas Scenario would have used the WEFA forecasts that 
contain the lowest reasonable projected gas prices.
---------------------------------------------------------------------------

    \835\ The Joint Commenters claims as to the Constant-Price-
Differential Base Case are probably meant as a reference to the 
Competition-Favors-Gas Scenario.
---------------------------------------------------------------------------

Commission Conclusion

    The claim that the assumptions unduly favor natural gas prices is 
incorrect. First, the assumption that lower gas prices will reflect 
favorably the environmental effects of the Rule is not valid. The 
impact of the Rule when gas prices are constant relative to coal is 
very close to the impact when gas prices are high relative to 
coal.<SUP>836 For example, the impact on total NO<INF>X emissions in 
2005 is higher when gas prices are constant relative to coal than when 
gas prices are high relative to coal (88,000 tons for the Constant-
Price-Differential Base Case versus 55,000 tons for the High-Price-
Differential Base Case).<SUP>837
---------------------------------------------------------------------------

    \836\ FEIS Chapter 6.
    \837\ Id. at Table 6-19 (page 6-23) and Table 5-18 (page 5-16), 
respectively.
---------------------------------------------------------------------------

    Second, the two price series were selected to give a range of 
variation in emissions that reflect differences in the price of gas 
relative to coal, rather than to project a ``correct'' natural gas 
price. As discussed in the FEIS, the Constant-Price-Differential Base 
Case reflects a continuation of the historical relationship between gas 
and coal prices over the past 10 years. Appendix G shows how forecasts 
over this period have consistently overestimated the price of gas 
relative to coal. It is therefore reasonable to consider the Constant-
Price-Differential Base Case as one side of a reasonable range.
    The prices selected for the other side of the reasonable range of 
gas prices relative to coal (the High-Price-Differential Base Case) 
were based on current forecasts at the time of the analysis. There were 
two primary reasons for selecting a lower gas price from the range of 
existing forecasts. First, the CEUM coal price forecast is determined 
within the model and could not be changed as an input. This coal price 
forecast was lower than the coal prices assumed in other forecasts. By 
picking a gas price forecast at the lower end of the range of current 
forecasts, and combining this forecast with the lower coal prices 
forecasts in CEUM, the analysis assumed a typical price of natural gas 
relative to coal.
    Second, at the time the analysis was conducted, all major 
forecasting organizations stated that they expected their gas price 
forecasts to be lower. However, these organizations did not complete 
their forecasts for several months. Since the available forecasts were 
up to a year old, there was reason to believe the forecasts overstated 
the current thinking among forecasters regarding future natural gas 
prices. This reason was confirmed by the forecasts that appeared around 
the time the analysis was completed. For example, the forecast for the 
wellhead price of natural gas in the year 2010 from the EIA published 
in January 1996 was $2.10 per million Btu, 15 percent below the 
forecast of $2.42 assumed for the High-Price-Differential Base Case in 
the FEIS.
8. Expanded Transmission Analysis
    Several commenters on the DEIS expressed concern that increases in 
transmission capacity resulting from open access might increase 
generation levels and thus air pollution. In response, the FEIS 
examined scenarios that increased transmission capacity substantially 
beyond current levels--including increases that the Commission believed 
would far exceed any transmission capacity increases that might occur 
as a result of the Rule. This analysis found that postulated increases 
in transmission do not affect emissions attributable to the Rule. The 
Commission also found that issues regarding enhancement of existing 
lines are more complex, and that this is due in part to the fact that 
state-level siting issues, the principal barrier to major increases in 
the transmission grid, are unaffected by the Rule. While competition 
will lead to improved efficiencies in generation, transmission will 
remain a regulated monopoly function. The Rule will reduce barriers to 
access, but will not open the transmission system to direct 
competition. Thus, the Commission concluded that the competitive 
effects of the Rule on transmission will be relatively small.<SUP>838
---------------------------------------------------------------------------

    \838\ FERC Stats. & Regs. at 31,872 n.974; mimeo at 691-92 
n.974.
---------------------------------------------------------------------------

Rehearing Requests

    The Joint Commenters claim that the expanded transmission analysis 
is unduly conservative. It states that the Commission increased peak 
transmission usage from 75 percent of first contingency total transfer 
capability (FCTTC) to 105 percent of FCTTC, and that this expanded 
transmission analysis represent minimal actual expansions, the most 
extreme of which barely increases FCTTC above current levels by the 
year 2010. The Joint Commenters claim that the Commission should have 
examined additional expansion potential in those analyses that more 
accurately demonstrate the effects of transmission expansion.

Commission Conclusion

    The Joint Commenters' claim that the expanded transmission analysis 
is inadequate is based on the premise that the FEIS used the wrong 
assumptions in developing transmission capacity. Joint Commenters 
contend that 100 percent of the FCTTC should have been used in CEUM. We 
believe that the use of 75 percent of this capacity to reflect annual 
capability is the appropriate level for modeling purposes. This 
reduction factor is necessary because the capability must be 
simultaneous systemwide capability and it must be sustainable. The 
FCTTC is a non-simultaneous ``snapshot'' transmission capability. The 
total simultaneous transfer capability is not accurately represented by 
adding together the

[[Page 12444]]

maximum transfer capability of each line in the system. The 
transmission system is a system. Loading on one line affects loading 
capability on all other lines in the system. This is especially true if 
the calculation is for capability over an extended period of time, as 
is the case with the FEIS, which uses transfer capability over one 
year. ``Derating'' as it has been called, is a reasonable way to 
represent the fact that a transmission system is capable of carrying 
less than the sum of the capabilities of the individual lines. Further, 
when modeling, if the model is calibrated so that the system is 
carrying actual historical flows--no matter what factor is used--the 
system will be carrying at or near its maximum capacity at constrained 
points which are the only points on the system where increased capacity 
would produce increased flows. As a result, increasing the transfer 
capability factor by up to 40 percent, as is done in the sensitivity 
analyses in Chapter 6 of the FEIS, represents a large change in the 
capability and use of the transmission system. Moreover, we note that 
this methodology has been used in previous CEUM analysis, where it was 
subject to review by electric utility experts.<SUP>839 For these 
reasons, the Joint Commenters' criticisms are invalid.<SUP>840
---------------------------------------------------------------------------

    \839\ Edison Electric Institute, Assessment of Greenhouse Gas 
Emissions Policies on the Electric Utility Industry: Costs, Impacts 
and Opportunities, prepared by ICF Resources, January 1992.
    \840\ See also FEIS Sections 3.4.2.1 and J.7.1.
---------------------------------------------------------------------------

    The Joint Commenters challenge the assumptions used in the 
Commission's expanded transmission analysis as ``unduly conservative'' 
and ``represent[ing] minimal actual expansions.'' Joint Commenters fail 
to explain in what respect they deem the expanded transmission analysis 
to be inadequate. They fail even to respond to the matters discussed by 
the Commission with regard to this issue in Order No. 888.
    As we noted above in the discussion of the PA Com's argument that 
the Commission failed adequately to consider the alternative of 
instituting open access pursuant to section 211 of the FPA, it is 
insufficient for a party to complain that an analysis is inadequate 
without providing specifics.

C. Mitigation

    The FEIS and Order No. 888 extensively assess the need for 
mitigation and discuss potential mitigation measures, including 
proposals advanced by commenters.<SUP>841 This discussion is perhaps 
best summarized by the conclusion to Chapter 7 of the FEIS, which 
states that:

    \841\ The EIS and Order No. 888 examine the specific mitigation 
proposals advanced by the Center for Clean Air Policy, the EPA, the 
Joint Commenters, the Project for Sustainable FERC Energy Policy, 
and the Department of Energy. FEIS at 7-28 through 7-43; FERC Stats. 
& Regs. at 31,877-82; mimeo at 705-17. The Commission concluded that 
the mitigation measures urged by the commenters are unwarranted, and 
that mitigation of the Rule is not required. Of the commenters 
advancing specific mitigation proposals in comments on the draft 
EIS, only the Joint Commenters seek rehearing of Order No. 888 on 
environmental issues. The Joint Commenters do not take issue on 
rehearing with the Commission's rejection of its mitigation 
proposal, but rather mounts a broad attack in which it asserts that 
the Commission has failed to properly consider and disclose the 
potential environmental effects of the Rule, and that the 
Commission's decision that it lacks authority to implement 
mitigation is contrary to law.
---------------------------------------------------------------------------

    This FEIS shows that the proposed rule is expected to slightly 
increase or slightly decrease total future NO<INF>X emissions, 
depending on whether competitive conditions in the electric industry 
favor natural gas or coal. The insistence of commenters that the 
Commission adopt and implement mitigation measures is based on 
significantly overstated assumptions regarding the contribution of 
the proposed rule to the existing environmental problems. The 
analysis presented in Chapter 6 establishes that overstated 
assumptions about the impact of the proposed rule are simply wrong.
    Nonetheless, in light of the importance of this issue, we have 
examined potential mitigation measures in detail, including those 
proposed by commenters, to ensure that environmental consequences of 
the rule have been fully and fairly evaluated. We do not believe 
mitigation should be undertaken in this rule because:
    Any mitigation measures the Commission might undertake are not 
justified by the small impacts of the rule, which impacts are as 
likely to be beneficial as they are to be harmful;
    The impacts of the proposed rule are dwarfed by the far larger 
ozone and NO<INF>X emission issues that either have nothing to do 
with the electric industry or will be unchanged by the rule or the 
larger open access program. We believe that it would be ineffective 
to address the NO<INF>X and ozone issues in a piecemeal way;
    The NO<INF>X issue is part of a long-standing, difficult set of 
inter-regional environmental issues. Representatives of many 
interests in both the Northeast and the Midwest have invested 
substantial efforts towards finding acceptable solutions through the 
OTAG process. Any mitigation the Commission might undertake could 
usurp EPA's mandate under the Clean Air Act and undermine progress 
towards comprehensive solutions sought by OTAG. This is not 
justified by impacts that are small and just as likely to be 
positive.
    We do not agree that the frozen efficiency reference case should 
be substituted for the EIS base cases or that competitive forces 
will favor coal over the next 15 years. But even accepting those 
assumptions, emissions attributable to the rule are relatively small 
until well after the turn of the century. So, even accepting such 
assumptions, the staff believes it would be unreasonable for the 
Commission to adopt mitigation requirements as part of the final 
rule; to do so would be tantamount to assuming that EPA and OTAG 
will not implement reasonable control measures in the next ten to 15 
years;
    The Federal Power Act and NEPA, either singly or conjointly, do 
not authorize the Commission to adopt and implement the proposed 
mitigation measures. The Commission does not possess (and has no 
mandate to possess) expertise on the extremely difficult issues 
involved in atmospheric chemistry and transport. It is fundamentally 
a economic regulatory agency. As a result, any mitigation measures 
the Commission undertook would be based on less-than-ideal 
information and analysis. It is unreasonable for the Commission to 
attempt such mitigation given the impacts found in this FEIS. This 
is especially true in light of the substantial additional research 
that EPA and OTAG are undertaking on the basic nature of the 
problem;
    Some suggested mitigation measures that might work at the 
transaction level would undermine the purpose of the rule. There is 
no justification for endangering the substantial benefits projected 
from the rule to mitigate a problem that might not exist and that 
is, in any case, likely to be small.<SUP>[842]
---------------------------------------------------------------------------

    \842\ FEIS at 7-47 and 7-48.

    The FEIS goes on to note that the long-term existence of a 
significant ozone nonattainment problem in parts of the country has led 
to the development of mechanisms to address this issue. It states that 
any incremental increases in NO<INF>X emissions that may result from 
the Rule can be addressed within this existing framework. In 
---------------------------------------------------------------------------
particular:

    The Clean Air Act authorizes EPA to establish transport regions 
that are charged with assessing the degree of interstate transport 
of pollutants, assessing mitigation strategies, and recommending 
revisions to State Implementation Plans to correct the problem. The 
Clean Air Act specifically establishes an ozone transport region for 
the Northeast. The jurisdictions that comprise the OTR have 
developed a coordinated approach to this problem that includes 
adopting a regional cap on NO<INF>X emissions.
    Although the OTR process is achieving its purpose, the problem 
is larger than the OTR can address. As a consequence, the Ozone 
Transport Assessment Group has been formed which encompasses the OTR 
and upwind states that contribute to nonattainment. OTAG is 
performing extensive photochemical grid modeling of the eastern U.S. 
to determine ozone transport patterns and to evaluate the efficiency 
of various control strategies. OTAG is considering imposing a cap 
and trade system for NO<INF>X emissions in a 37-state area comprised 
of the Northeast OTR and upwind states. If the cap and trading 
system becomes

[[Page 12445]]

effective it should fully mitigate NO<INF>X emission increases, if 
any, attributable to open access transmission within the 37-state 
area. A cap and trade program is also likely to mitigate CO<INF>2 
and mercury emissions.
    We believe that the cap and trading system under consideration 
in the OTAG process is the preferred approach to the overall 
NO<INF>X emissions problem. The OTAG process brings to the table the 
parties that must participate in making the difficult decisions to 
fully resolve this problem. The OTAG process possesses the technical 
resources and expertise to address the difficult scientific and 
technical issues that must be resolved to remedy this problem. More 
limited approaches cannot render a satisfactory solution. We respect 
the expertise and the goals of the OTAG process and do not believe 
we can or should substitute for them in addressing this long-term 
national problem.<SUP>[843]
---------------------------------------------------------------------------

    \843\ Id. at 7-49.
---------------------------------------------------------------------------

Rehearing Requests

    Pennsylvania PUC. The PA Com claims that the Commission has 
inappropriately declined to assume any responsibility for mitigating 
environmental impacts associated with the Rule. It states that the 
Commission has authority to take mitigation measures related to its 
regulatory actions and that the Commission can reasonably add 
environmental impacts to the list of factors to be weighed under the 
FPA's public interest standard. In this regard, it contends that the 
FPA grants FERC authority to place conditions on the regulation of 
rates and conditions of wholesale power sales and the interstate 
transmission of electric power as well as to order wholesale wheeling 
under certain circumstances.
    The PA Com states that the Commission should act to minimize the 
likelihood of significant additional NO<INF>X emissions by developing a 
mitigation plan to be implemented in conjunction with the Rule, and 
that FERC should use the results of the OTAG process to provide 
information to develop this strategy. The PA Com concludes that FERC 
should not require open access generically.
    Vermont Department of Public Service. The Vermont Department of 
Public Service (VT DPS) contends that the Commission erred in failing 
to establish a monitoring program and a periodic reopener provision to 
address environmental considerations. VT DPS submits that the 
Commission has given inadequate consideration to the possibility that 
the Rule may unnecessarily exacerbate environmental impacts. It notes 
EPA's claim in its referral letter to the Council on Environmental 
Quality (CEQ) that any future NO<INF>X increases resulting from open 
access would exacerbate the difficulty of accomplishing reductions in 
NO<INF>X emissions.
    VT DPS claims that the environmental review process has not 
facilitated the ability of affected parties to review all modeling 
assumptions. It also claims that other environmental reviews suggests 
more serious NO<INF>X emission consequences of the Rule than 
acknowledged by the Commission.
    VT DPS states that given the possibility that the FEIS conclusions 
may prove wrong, the Commission should take steps to permit timely 
reevaluation of its program. VT DPS recommends that the Commission 
establish an ongoing monitoring program to determine if the Rule poses 
an unacceptable risk to air quality. It states that a monitoring 
program would allow the Commission to take timely action to mitigate 
any unintended consequences of the Rule. The Commission should also 
provide for periodic reevaluation of the Rule's open access provisions 
and should commit to a comprehensive reevaluation of the Rule's 
environmental impacts every five years over the next 20 years.
    New York Attorney General. The New York Attorney General (Attorney 
General) states that the federal government should ensure that New York 
and other Northeast states do not bear the burden of any increased air 
pollution resulting from deregulation.<SUP>844
---------------------------------------------------------------------------

    \844\ The New York Attorney General wrote to the Commission on 
May 13, 1996 expressing concern about the potential environmental 
effects of the Rule. Its filing does not appear to constitute a 
request for rehearing, but it is treated here as such.
---------------------------------------------------------------------------

    The Attorney General asserts that utilities in upwind states have a 
competitive advantage relative to Northeast utilities because they are 
subject to less extensive environmental controls. The Attorney General 
contends that deregulation may result in these plants increasing 
generation, thus increasing emissions that will contribute to the 
inability of New York and the Northeast to meet the federal ozone 
standard. The Attorney General claims that, regardless of the effects 
of the Rule, studies show that a 50 percent reduction in NO<INF>X 
emissions from all sources east of the Mississippi will be necessary 
for New York and other Northeast states to achieve the ozone standard.
    The Attorney General states that Congress has placed limits on 
EPA's authority to protect New York from upwind emissions, and that it 
is therefore essential that FERC exercise any authority it may have to 
mitigate the environmental effects of the Rule.
    The Attorney General claims that EPA's proposal in its February 20, 
1996 comments to place a cap on NO<INF>X emissions would mitigate the 
effects of the Rule; it suggests basing this system on the MOU pursuant 
to authority residing in EPA and/or FERC. Under this proposal, a 
utility would be permitted to take advantage of deregulation if it 
simultaneously takes steps to prevent emission increases.
    Joint Commenters--Overview. The Joint Commenters state that FERC 
has failed to consider and disclose the potential environmental effects 
of the Rule, and that FERC's decision that it lacks authority to 
implement mitigation is contrary to law.
    The Joint Commenters' premise is that, despite deficiencies in the 
Commission's analysis which understate the effects of the Rule, the 
FEIS nonetheless presents data confirming that open access will have 
significant adverse environmental impacts. Joint Commenters posit that 
increased emissions from open access could seriously threaten 
achievement of Clean Air Act requirements and other environmental 
commitments. It reasons that the Commission therefore must develop and 
implement environmental mitigation.
    The Joint Commenters begin with the assertion that the data 
presented in the FEIS do not support the conclusion that the effect of 
the Rule on air pollution will be insignificant. It claims that the 
Commission relied on cases that show small impacts. Joint Commenters 
note in this regard that EPA has determined that any increase in 
NO<INF>X emissions from restructuring is unacceptable and should be 
remedied.
    Joint Commenters then assert that FPA sections 205 and 206 require 
the Commission to adopt mitigation. It claims that case law supports 
the proposition that both NEPA and the FPA authorize FERC to mitigate 
the adverse environmental impacts arising from its action. Even 
assuming arguendo that it was reasonable for the Commission to reject 
specific proposed mitigation measures, it is unreasonable the deny the 
existence of authority to mitigate. The Commission should remedy this 
by adopting mitigation concurrent with implementation of Order No. 888.
    According to Joint Commenters, the FEIS establishes that 
competitive electric markets will likely result in higher utilization 
of heavily polluting coal-fired generation. Thus, in view of EPA's 
statement in its referral to CEQ that any increase in NO<INF>X 
emissions could seriously undermine attainment of health based 
standards, the FEIS

[[Page 12446]]

finding that emission increases that may be as large as 315,000 tons 
per year are insignificant is not supported by the record.
    Joint Commenters then argue that not only does the decision not to 
implement mitigation measures risk nonattainment of public health 
goals, it will fail to achieve the regulatory objective of fair and 
efficient bulk power competition. It contends that without concurrent 
environmental mitigation, the Commission will put in place a market 
structure that is inherently discriminatory and that arbitrarily shifts 
costs. It states that Order No. 888, in effect, provides a class of 
competitors with an undue preference subsidy. This undue preference 
results from the fact that the owners of coal-fired generation that are 
not subject to emissions regulation will be able to shift financial 
responsibility for their pollution to competitors in downwind regions. 
This discriminatory situation will distort the bulk power market and 
produce inefficiencies that the Commission has not addressed.<SUP>845
---------------------------------------------------------------------------

    \845\ This aspect of the Joint Commenters' argument is addressed 
below.
---------------------------------------------------------------------------

    Open Access Will Have Significant Adverse Impacts. The Joint 
Commenters state that some FEIS scenarios show that restructuring is 
likely to have significant adverse environmental effects. It claims 
that the sensitivity analyses confirm that low-cost, high-emission coal 
plants may increase their capacity utilization from an average of 62 
percent in 1993 to 81.5 percent by 2010 and that this increase is 
associated with an additional 515 billion kWh of coal generation per 
year by 2010 above 1993 levels, assuming expanding transmission. FEIS 
data further indicate that 110 billion kWh of this annual increase by 
the year 2010 will be attributable to competition under the open access 
policy compared to the frozen efficiency case.
    The Joint Commenters assert that the FEIS also confirms that this 
increase in coal-based generation will increase NO<INF>X emissions 
across the 37-state OTAG region by 250,000 tons per year by 2010 
(315,000 tons for the entire U.S.) and result in a cumulative NO<INF>X 
emissions increase across the U.S. of 530,000 tons by 2000 and 2.7 
million tons by 2010.
    The Joint Commenters assert that the impacts of a 250,000 ton 
NO<INF>X increase across the OTAG region are extremely significant, 
particularly in downwind nonattainment areas, and fly in the face of 
EPA's determination that any increase is unacceptable.
    The Joint Commenters contend that the Commission understates the 
significance of these numbers by emphasizing percentages and using 
national figures. According to Joint Commenters, the FEIS demonstrates 
that regional increases in NO<INF>X include a seven percent increase in 
the East North Central region, 10 percent in the Mountain region and 26 
percent in the Pacific regions. These references are to emissions in 
2005. The percentages in the year 2010 are approximately five percent 
nationally, rather than the three percent discussed in Order No. 888.
    The Joint Commenters state that the FEIS also shows that increased 
utilization of coal plants could significantly add to utility carbon 
dioxide (CO<INF>2) emissions, which would conflict with the Clinton 
Administration's commitment to stabilize greenhouse gas emissions at 
1990 levels by the year 2000. It states that the Competition-Favors-
Coal Scenario projects that annual utility CO<INF>2 emissions will 
increase by 285 million tons by 2000 and by 737 million tons by 2010; 
and that the FEIS attributes about 10 percent of the increase to the 
Rule. It argues that this increase will threaten international 
commitments of the U.S. Government. The Joint Commenters assert that 
utility CO<INF>2 emissions are not currently on track to fulfill 
national and international climate protection objectives and open 
access competition, to the extent it favors existing coal plants, will 
exacerbate these trends.
    The Joint Commenters then claim that in addition to the emissions 
impacts that are identified in the FEIS, EPA's technical analysis 
indicates that the Rule has the potential to cause much larger impacts 
than the FEIS estimates for the Competition-Favors-Coal Scenario. EPA's 
evaluation, which Joint Commenters claim does not incorporate worst 
case scenario assumptions, indicates that the potential increases in 
NO<INF>X emissions from open access could be more than twice the 
increases projected in the FEIS Competition-Favors-Coal Scenario in 
years 2000, 2005 and 2010. The potential that FERC's highest polluting 
case understates emissions increases to this extent illustrates the 
uncertainty surrounding the impacts of open access, particularly the 
uncertainties surrounding the accuracy of the Commission's estimates, 
and the critical importance of developing mitigation programs.
    Authority to Mitigate. The Joint Commenters assert that the 
Commission's rejection of authority to mitigate environmental impacts 
is contrary to law and arbitrary and capricious. It states that the 
Commission's rejection is inconsistent with Commission claims about its 
sections 205 and 206 authority, and that both NEPA and the FPA permit 
FERC to mitigate adverse environmental impacts. Thus, while it may be 
reasonable for the Commission to reject specific mitigation measures, 
the Commission's decision that it lacks authority to implement 
mitigation constitutes an arbitrary and capricious exercise of agency 
authority.
    The Joint Commenters argue that NEPA authorizes agencies to 
consider and address environmental impacts so long as any actions 
undertaken do not conflict with the agency's authorizing statute. It 
states that a number of cases support the proposition that FERC's FPA 
authority is broadened by NEPA--that NEPA policies and goals inform and 
expand the FPA's definition of public interest. In effect, NEPA 
establishes a legal nexus between the Commission's primary regulatory 
duties and environmental protection. Thus, courts have upheld agency 
mitigation actions under NEPA even when the agencies have no explicit 
environmental protection mandate. The Joint Commenters assert that the 
Commission did not address these cases in concluding that it lacks 
authority to mitigate adverse environmental impacts under sections 205 
and 206 and the FPA's general public interest standard.
    The Joint Commenters assert that if NEPA is to be given practical 
effect, agencies must have authority to do more than study the 
potential environmental impacts of proposed actions. To interpret and 
administer federal laws in accordance with NEPA policies, agencies must 
have the authority to use their statutory powers in ways that implement 
NEPA policies. The arena of permissible environmental action is 
constrained only by the limits of the agency's jurisdictional authority 
under its enabling statutes. Thus, the only limits on FERC's ability to 
implement environmental mitigation are those defined by the FPA. 
Therefore, the question is whether mitigation falls within the 
regulatory powers of FERC.
    The Joint Commenters argue that the FPA authorizes the Commission 
to mitigate the environmental effects of its actions, stating that the 
public interest standard of FPA section 201 encompasses the 
environmental and other competitive concerns discussed in its request 
for rehearing. The Joint Commenters state that NAACP v. FPC, 425 U.S. 
662 (1976) and similar cases establish that FERC has jurisdiction to 
address environmental concerns since such concerns are directly related 
to FERC's regulation of economic interests in the electric industry.
    The Joint Commenters assert that FERC's duty to ensure just and

[[Page 12447]]

reasonable rates that are not unduly discriminatory or preferential 
also encompasses non-economic factors in appropriate circumstances. It 
argues that the Commission's reliance on Office of Consumers' Counsel 
v. FERC, 655 F.2d 1132 (D.C. Cir. 1980), to support its narrow reading 
of the FPA's public interest standard is misplaced.
    The Joint Commenters then take issue with the position that the 
Commission lacks authority to implement mitigation because it has 
insufficient expertise in air pollution control and because Congress 
gave EPA authority to address such issues. It states that the record 
does not support a conclusion that FERC lacks the expertise necessary 
to provide for mitigation of the Rule's impacts. Moreover, nothing 
would prevent the Commission from acting in concert with EPA to take 
advantage of EPA's expertise.
    The Joint Commenters state that, unlike the situation in Office of 
Consumers' Counsel, Congress has given FERC, along with EPA and other 
federal agencies, the responsibility to address the environmental 
effects of its actions. In this case, Joint Commenters are asking the 
Commission to mitigate the environmental impacts of its Rule, not to 
assert jurisdiction proactively over air pollution matters or to usurp 
EPA's role. Under Order No. 888's logic, no federal agency would have 
authority to mitigate the environmental impacts of its proposed actions 
because EPA is the primary agency with environmental expertise and 
responsibility.
    The Joint Commenters then argue that the Commission's jurisdiction 
to consider environmental issues also derives from a traditional 
analysis of FERC's jurisdiction over wholesale power rates. It states 
that if the Commission does not allocate environmental responsibility 
to high-emission utilities, environmental compliance costs will be 
transferred to downwind utilities and their customers. These utilities 
will be required to incur costs to reduce emissions and must increase 
rates to recapture these costs. Thus, Order No. 888 will directly 
affect the costs that are included in electric rates, which the 
Commission has authority to review under sections 205 and 206.
    The Joint Commenters conclude their discussion by noting that, 
while it may have been reasonable for the Commission to reject specific 
mitigation proposals, the Commission should reexamine the position that 
it has no authority in this area and instead acknowledge that the 
exercise of that authority is not warranted here given the conclusions 
in the FEIS. The Joint Commenters go on to note that EPA proposed in 
its referral to CEQ a mitigation approach that seeks the Commission's 
commitment to future actions and outlines immediate actions EPA will 
take to address the potential NO<INF>X emission increases identified in 
the FEIS. The Joint Commenters state that although it believes EPA's 
proposal is reasonable and strongly support the tracking system 
recommended, the Commission should develop a backup NO<INF>X mitigation 
mechanism by the end of 1996 to assure that Order No. 888 will be 
implemented without adverse environmental impacts.

Commission Conclusion

    Need for Mitigation. The FEIS examines fully claims that the Rule 
will have significant environmental impacts requiring mitigation. As 
stated in Order No. 888:

    First, the findings show that, without the rule, NO<INF>X 
emissions are expected to decline until at least the year 2000. 
Thereafter, again without the rule, NO<INF>X emissions are expected 
to increase steadily through the year 2010 (the end of the FEIS 
study period). The extent of the decrease and the increase will be 
largely determined by the relative prices of natural gas and coal, 
the two main fuels used to generate electric power in most regions.
    In reaching this conclusion, the FEIS used two ``base'' cases. 
In one (the ``High-Price-Differential Base Case''), natural gas was 
assumed to become substantially more expensive compared with coal 
than it is today. In the other (the ``Constant-Price-Differential 
Base Case''), natural gas was assumed to maintain essentially the 
same price relative to coal that has existed for the last ten years. 
The two cases describe the range of emissions due to fuel price 
uncertainty without the rule and demonstrate the overall trends of 
decreases until 2000 and increases thereafter.
    Second, the FEIS finds that the rule will not in any significant 
respect affect these overall trends.
    The potential impact of the rule was studied initially under two 
scenarios. In one (the ``Competition-Favors-Gas Scenario''), the 
rule is assumed to result in efficiency gains in the electric 
industry that would tend to favor natural gas as a fuel. In this 
scenario the effect of the rule is slightly beneficial. Total 
NO<INF>X emissions are reduced overall by about two percent 
nationwide from the base cases. In the other (the ``Competition-
Favors-Coal Scenario''), the rule is assumed to result in efficiency 
gains in the electric industry that would tend to favor coal as a 
fuel. In this scenario the effect is again slight, showing 
approximately a one percent increase in NO<INF>X emissions 
nationwide from the base cases. In both scenarios, however, the rule 
does not have an overall effect on NO<INF>X emission trends.
    Stated differently, under any case studied, with or without the 
rule, there will be an overall net decrease in NO<INF>X emissions 
through the year 2000. Thereafter, NOx emissions begin to increase. 
The rule does not materially affect either the decline prior to 2000 
or the increase thereafter.
    Based on these findings the Commission concludes that a 
comprehensive, Commission-imposed mitigation scheme to address the 
environmental consequences of the rule is not appropriate. If 
competition favors gas, the effects are beneficial and mitigation is 
unnecessary. If competitive conditions favor coal through the year 
2010, and NO<INF>X emissions increase slightly as a result of the 
rule, these minor effects would be effectively mitigated as a part 
of a comprehensive NO<INF>X cap and trading allowance scheme 
developed by EPA in cooperation with the Ozone Transport Assessment 
Group (OTAG) and administered by EPA and state environmental 
regulators under the clearly established authority of the Clean Air 
Act. [<SUP>846]
---------------------------------------------------------------------------

    \846\ FERC Stats. & Regs. at 31,862-63; mimeo at 663-65 
(footnotes omitted).

    The Commission went on to note that it believes the appropriate no-
action alternative was used to conduct this analysis. ``An alternative 
that requires the Commission to reverse all its other open access 
policies is simply not a 'no-action' alternative. To the contrary, it 
would require decisive action running counter to the direction from the 
Congress in the Energy Policy Act and the needs of the marketplace and 
---------------------------------------------------------------------------
electricity consumers.'' <SUP>847 The Commission then explained:

    \847\ Id. at 31,863; mimeo at 665.
---------------------------------------------------------------------------

    However, to ensure that the effects of the rule were analyzed 
fully, the FEIS did study a reference case based on the ``frozen 
efficiency'' case proffered by EPA and the Department of Energy 
(DOE). Although, as described below, we believe this case to be 
highly unlikely, the results show that, even under this scenario, 
the impacts of the rule are not great and do not vary significantly 
from those projected by staff under the other assumptions.
    In one case requested by EPA, staff studied a combination of 
assumptions most likely to show significant increases in emissions 
associated with the rule; the case included EPA's frozen efficiency 
scenario, coupled with the ``Competition-Favors-Coal'' assumptions. 
Other cases requested by EPA posit dramatic increases in 
transmission capacity (that we find highly unlikely). Even this 
combination of assumptions--geared to demonstrate the greatest 
impact the rule might have on increased NO<INF>X emissions--produced 
little in the way of environmental consequences associated with the 
rule. Under these extreme (and unlikely) conditions, there would 
still be a net decrease in NO<INF>X emissions until at least the 
year 2000, albeit a smaller decrease than in the base cases. 
Comparing projections of emissions for the same years, emissions 
would be higher than the base cases only by two percent in 2000 and 
three percent in 2005. It is only in the year 2010, assuming these 
improbable scenarios, that NO<INF>X emissions associated with the 
rule would be higher than the base case by even five percent.

[[Page 12448]]

    Based on these studies, including the EPA reference case, the 
Commission endorses the staff findings that the rule will affect air 
quality slightly, if at all, and that the environmental impacts are 
as likely to be beneficial as negative. This is true even under 
scenarios contrived to maximize emissions associated with the rule 
under circumstances that this Commission believes to be highly 
unlikely.
    Importantly, this is also true in the near-to mid-term. Until 
the year 2010, even the worst case (the frozen efficiency case) 
produces results very similar to those produced using assumptions 
the Commission believes to be reasonable. In short, the rule will 
not produce an ``ozone cloud'' coming across the Appalachians to 
threaten the Northeast on the day the rule goes into effect. 
Assuming that any environmental impacts occur, they are years in the 
future and may well be beneficial. As a result, calls for Commission 
mitigation, and in particular for interim mitigation to ``fill the 
gap'' until programs under the Clean Air Act can be adopted, are 
unnecessary and disproportionate to the possible effects of the 
rule. [ <SUP>848]

    \848\ Id. at 31,863-64; mimeo at 665-67 (footnotes omitted).
---------------------------------------------------------------------------

    Thus, there is no basis for claims that the Rule will result in 
large increases in pollution from generating plants operating under 
less stringent environmental controls. This negates arguments calling 
for the imposition of mitigation measures to ensure that all entities 
compete under an identical regulatory regime.
    We note in this regard that the Joint Commenters' claim that the 
Rule may result in emissions increases as large as 315,000 tons per 
year by the year 2010, and cumulative NO<INF>X increases across the 
United States of 530,000 tons by 2000 and 2.7 million tons by 2010, is 
incorrect. The Joint Commenters derive this result by selectively 
choosing numbers from the FEIS, comparing sensitivity cases designed to 
be unrealistically low and high extremes. The low emissions case 
selected is the frozen efficiency case that represents a complete 
reversal of current industry and regulatory trends that are occurring 
without the Rule. The high emissions case represents an increase in 
transmission capacity that cannot reasonably be ascribed to the Rule. 
The FEIS indicates that these cases were used to examine the 
sensitivity of findings to certain extreme assumptions maintained by 
commenters and are not the appropriate cases to use for considering 
potential environmental impacts from the Rule.
    Moreover, the Joint Commenters reference increases from the Rule 
without noting equally likely decreases. Even with the lower emissions 
resulting from the unrealistic frozen efficiency case, the FEIS finds 
decreases in emissions from the Rule when competitive forces lead to 
greater efficiency for natural gas generation compared to coal.
    Actions to Mitigate NO<INF>X Emissions. Moreover, EPA and the 
Commission have committed to undertake the actions sought by those 
seeking rehearing on this issue. EPA in its referral to the CEQ 
concurred with the Commission ``that the open access rule is unlikely 
to have any significant adverse environmental impact in the immediate 
future, and that in light of its anticipated economic benefits, 
implementation of the Rule should go forward without delay.'' EPA also 
``concludes that the FERC has conducted an adequate analysis under the 
National Environmental Policy Act of the environmental impacts of the 
open access rule under a range of possible scenarios.'' In particular, 
EPA concurs that the ``FERC made a reasonable choice of models (CEUM) 
and made assumptions for various factors input into the model that lie 
within the range of reasonable assumptions.''
    EPA also concurred with the Commission that NO<INF>X emissions 
increases associated with the Rule, if any, should be addressed as part 
of a comprehensive NO<INF>X emissions control program developed by EPA 
and the states under mechanisms available under the Clean Air Act. This 
includes support for the efforts of OTAG to develop standards for 
measuring the scope of the ozone transport problem and developing 
emissions reduction strategies.
    More significantly, EPA committed to use its authority under the 
Clean Air Act to support successful completion of the OTAG process. EPA 
will establish a NO<INF>X cap-and-trade program for the OTAG region 
through Federal Implementation Plans ``if some States are unable or 
unwilling to act in a timely manner.'' <SUP>849
---------------------------------------------------------------------------

    \849\ The FEIS at page 7-8 discusses EPA's authority under the 
Clean Air Act to remedy the interstate transport of air pollution. 
Section 176A provides that whenever EPA has reason to believe that 
the interstate transport of air pollutants from one or more states 
contributes significantly to a violation of national ambient air 
quality standards in one or more other states, it may establish a 
transport region for such pollutant. The transport commission is 
charged statutorily with assessing the degree of interstate 
transport of the pollutant or precursors to the pollutant throughout 
the transport region, assessing strategies for mitigating the 
interstate pollution, and recommending to the EPA Administrator 
measures to ensure that the relevant State Implementation Plans 
(which every state is required to have in place to address air 
pollution) meet the requirements of the Clean Air Act.
    A transport commission may request the Administrator to issue a 
finding under section 110(k)(5) that the SIP for one or more of the 
states in the transport region is substantially inadequate to meet 
the requirements of section 110. The Administrator must approve or 
disapprove such a request within 18 months of its receipt.
    Upon approval of recommendations submitted by the transport 
commission, the Administrator must issue to each state in the OTR to 
which a requirement of the approved plan applies, a finding under 
section 110(k)(5) that the implementation plan for such state is 
inadequate to meet the requirements of section 110. Such finding 
shall require each such state to revise its SIP to include the 
approved additional control measures within one year after the 
finding is issued.
---------------------------------------------------------------------------

    EPA also states that if ``the OTAG and Clean Air Act processes fail 
to produce the necessary pollution limitations in a timely manner, EPA 
will call upon all other interested Federal agencies to assist in 
solving the problem.'' In this context EPA would ask the Commission to 
contribute by further examining, through a Notice of Inquiry, possible 
strategies for mitigating NO<INF>X emissions increases associated with 
the Rule. EPA also suggested that if it determines that the problem 
must be addressed through EPA initiation of Federal Implementation 
Plans, FERC could then initiate a rulemaking to propose ``suitable 
means under the Federal Power Act'' for mitigating impacts attributable 
to the Rule.
    The Commission, on May 29, 1996, issued an order responding to 
EPA's referral. The Commission stated that:

    Given EPA's commitment to address air pollution issues, it is 
appropriate for EPA to seek assurances that if its best efforts are 
not successful, other agencies will examine their abilities to 
address the problem within the scope of their respective statutory 
authorities. Given the broad powers vested in EPA by the Clean Air 
Act, we fully expect EPA to succeed. We also note that if EPA is 
unable ultimately to address the issue, either through the voluntary 
OTAG process or by means of its authority under the Clean Air Act, 
we doubt that other agencies will be able to resolve the NO<INF>X 
emissions problem under more limited authority. In such 
circumstances, action by the Congress may be necessary.
    Nevertheless, we believe that the Commission should be willing, 
if called upon under the circumstances EPA describes, to consider 
whether, under the Federal Power Act, it can and should attempt to 
address NO<INF>X emissions issues attributable to the Rule. 
Therefore, if EPA concludes that the OTAG process has not succeeded 
in meeting its objectives in a timely manner, we will initiate a 
Notice of Inquiry to further examine what mitigation might be 
permissible and appropriate under the Federal Power Act. Such an 
inquiry would solicit public comment on how to assess appropriately 
the air pollution impacts attributable to the Final Rule, suitable 
ways in which to address such impacts, if any, and the scope of the 
Commission's authority to address such impacts.

[[Page 12449]]

    Additionally, under the extraordinary circumstances in which EPA 
would undertake a Federal Implementation Plan, the Commission would 
agree to initiate contemporaneously a rulemaking to propose possible 
mitigation that could be undertaken by the Commission under the 
Federal Power Act. Such a rulemaking would be undertaken on the 
basis of the NOI mentioned above and would be appropriate only if 
environmental harm attributable to the rule that warranted 
mitigation is demonstrated. The Commission would rely upon 
information gleaned in the NOI in proposing possible mitigation 
strategies that are workable, tailored to address consequences 
attributable to the Rule, and consistent with our statutory 
authority. In no event would the Commission propose a mitigation 
strategy that would undermine the purposes of the rule to provide 
open transmission access on a non-discriminatory basis. We emphasize 
that neither the NOI nor the rulemaking, if they occur, will affect 
the implementation of the rule as required under Orders of the 
Commission. [<SUP>850]

    \850\ Order Responding to Referral to Council on Environmental 
Quality, 75 FERC para. 61,208 at 61,691-92 (1996).
---------------------------------------------------------------------------

    Thus, EPA has concluded that the Commission conducted an adequate 
analysis of the impacts of the Rule and agrees that the Rule is 
unlikely to have any significant adverse environmental impact in the 
near future. EPA also concurs that NO<INF>X emissions increases 
associated with the Rule, if any, should be addressed as part of a 
comprehensive NO<INF>X emissions control program developed by EPA and 
the states under mechanisms available under the Clean Air Act. This 
includes support for the efforts of OTAG to develop emissions 
reductions strategies. EPA will use its Clean Air Act authority to 
support completion of the OTAG process. EPA is prepared to establish a 
NO<INF>X cap-and-trade program for the OTAG region through Federal 
Implementation Plans if states are unable or unwilling to act in a 
timely manner.
    This commitment by EPA puts to rest the concerns expressed by those 
seeking rehearing on the issues of mitigation and disparate emissions 
standards. As stated in the FEIS:

    The Ozone Transport Assessment Group (OTAG) represents [a] 
broad[] effort to deal with the interstate transport of pollutants 
that form ozone. OTAG is a voluntary organization that consists of 
37 eastern states, the District of Columbia, and the EPA; industry 
and environmental groups also participate in the OTAG process. It 
was organized by the Environmental Council of States to study the 
transport of ozone and its precursors in the eastern U.S. and to 
develop mitigation strategies. OTAG is performing extensive 
photochemical grid modeling to determine ozone transport patterns 
and to evaluate the efficiency of various control strategies. OTAG 
intends to submit its findings regarding transport patterns and its 
recommendations for mitigation of ozone transport to EPA by January 
1997.
    OTAG is considering a number of strategies to mitigate the 
problem of ozone nonattainment. One strategy is the imposition of a 
cap and trading system for NO<INF>X emissions in a 37-state area 
compromising the Northeast OTR and upwind states. If the cap and 
trading system becomes effective, it will fully mitigate any 
NO<INF>X emissions increases attributable to open access 
transmission within the 37-state area, because increases within this 
area would have to be offset by a corresponding emission reduction.
    The OTAG cap and trade program may not deal directly with 
emissions of pollutants other than NO<INF>X. However, a cap on 
NO<INF>X is likely to mitigate CO<INF>2 and mercury increases, 
because internalizing costs of NO<INF>X controls on coal-fired units 
is likely to dampen increases in capacity utilization of such 
units.<SUP>[851]
---------------------------------------------------------------------------

    \851\ FEIS at 7-10 through 7-11.

    The OTAG process includes the players of concern here--both the 
states from which alleged pollution increases would originate and the 
states that would be affected by the increased pollution. OTAG has a 
process underway to determine transport patterns and to evaluate 
control strategies. One strategy that is being considered is the 
imposition of a cap and trade system for NO<INF>X emissions like that 
sought on rehearing here.<SUP>852 OTAG originally intended to submit 
its findings regarding transport patterns and recommendations for 
mitigation to EPA by January 1997. As a result of its decision to 
conduct additional modeling to determine the appropriate geographic 
applicability of emission reduction strategies, OTAG has extended its 
January timeframe by a few months, and now intends to complete its 
process by April or May 1997.
---------------------------------------------------------------------------

    \852\ We note in this regard that in a recently completed 
rulemaking promulgating standards for the second phase of the 
Nitrogen Oxides Reduction Program under Title IV of the Clean Air 
Act, EPA authorized states to adopt a NO<INF>X cap and trading 
program under certain circumstances. ``Acid Rain Program; Nitrogen 
Oxides Emission Reduction Program'', 61 FR 67112, 67163 (1996).
---------------------------------------------------------------------------

    While OTAG is continuing its efforts, EPA is moving rapidly forward 
to remedy in a comprehensive fashion the interstate transport of air 
pollution. On January 10, 1997, EPA issued a notice of intent to use 
the authority granted it by sections 110(k)(5) and 110(a)(2)(D) of the 
Clean Air Act to require states to submit state implementation plan 
(SIP) measures to ensure that emission reductions are achieved as 
needed to prevent significant transport of ozone pollution across state 
boundaries in the Eastern United States. This notice ``announces EPA's 
intention to conduct the formal process for implementing the regional 
reductions in ozone precursors that are necessary for areas in the 
Eastern United States to reach attainment.'' <SUP>853 EPA states that 
it intends to publish a Notice of Proposed Rulemaking in March 1997 
that ``will propose overall amounts or ranges of NO<INF>X and/or VOC 
emission reductions that each State would need to achieve to reduce the 
boundary condition concentrations of ozone and its precursors within a 
specified timeframe and require the submission of SIP controls to 
achieve these reductions.'' <SUP>854 The notice of inquiry also states 
that the SIP revision must contain a schedule for adoption and 
implementation of these measures. It notes that while EPA could allow 
up to 18 months for SIP submittals under section 110(k)(5), ``EPA is 
considering a more accelerated schedule for submittals under this SIP 
call to attain air quality benefits sooner and to facilitate area 
specific SIP planning.'' <SUP>855 EPA notes that as it goes through the 
process of developing an implementation program for the new standard, 
it will be able to take advantage of the information gathered by OTAG 
and account for emission reductions that result from the recommended 
strategy. EPA intends to publish the final SIP call notice in summer 
1997.
---------------------------------------------------------------------------

    \853\ 62 FR 1420 (1997).
    \854\ Id. at 1423.
    \855\ Id.
---------------------------------------------------------------------------

    Thus, actions to address the concerns with regard to mitigation and 
emissions standards disparity are taking place at this time and should 
be in place in the near future. This lays to rest as well concerns that 
any near-term impacts of the Rule have not been taken into account.
    The Commission's Authority to Mitigate. The PA Com makes an 
unsupported assertion that the FPA's public interest standard 
authorizes the Commission to take mitigation measures related to its 
regulatory actions, and that the Commission should use the results of 
the OTAG process to develop a mitigation strategy.
    The Joint Commenters argue that the Commission has broad authority 
under NEPA to mitigate the environmental consequences of its proposed 
actions. It contends that NEPA broadens the Commission's FPA 
authority--that NEPA policies and goals inform and expand the FPA's 
definition of the public interest. It also argues that the Commission's 
duty to ensure just and reasonable rates that are not unduly 
discriminatory or preferential also

[[Page 12450]]

encompasses non-economic factors in appropriate circumstances.
    The Joint Commenters conclude that, while it may be reasonable for 
the Commission to reject specific proposed mitigation measures, the 
Commission should, at a minimum, acknowledge that the FEIS demonstrates 
that the exercise of that authority is not warranted in this case. The 
Joint Commenters add that the Commission should initiate a rulemaking 
proceeding that considers mitigation options and evaluates the 
effectiveness of alternative strategies and proposals. The Joint 
Commenters concur that EPA's commitment to address air pollution issues 
is reasonable, but would have the Commission develop a backup NO<INF>X 
mitigation mechanism by the end of 1996.
    Thus, the PA Com and the Joint Commenters would have the Commission 
revisit in this order, by means of a generalized reexamination of the 
Commission's authority to impose mitigation, the conclusion in Order 
No. 888 that the mitigation measures recommended by commenters are 
beyond our authority to implement.
    Order No. 888 and the FEIS fully examine the need for mitigation 
and the Commission's legal authority to impose mitigation measures. 
That examination led to the conclusion that: (1) the insistence of 
certain commenters that the Commission adopt and implement mitigation 
measures is based on significantly overstated assumptions regarding the 
contribution of the Rule to existing environmental problems, and that 
these assumptions about the impact of the Rule are wrong; (2) the 
existence for many years of a significant ozone nonattainment problem 
in part of the U.S. has led to the development of mechanisms to address 
this issue; (3) the mitigation recommendations suggested by commenters 
suffer from serious legal and practical shortcomings; and (4) the 
mitigation measures recommended by commenters are beyond the 
Commission's authority to implement and strong policy considerations 
militate against their adoption.
    The PA Com and Joint Commenters have not raised any arguments that 
warrant revisiting the Commission's exhaustive examination of this 
issue in Order No. 888 and the FEIS, and we hereby reaffirm those 
decisions. We note in this regard that the PA Com did not advance a 
specific mitigation proposal in comments on the EIS and does not 
challenge the Commission's rejection in Order No. 888 of specific 
mitigation proposals advanced by other commenters. The Joint Commenters 
did propose a specific mitigation strategy which the Commission 
rejected because, among other things, it would have the Commission 
impose a revenue collection measure. The Joint Commenters do not 
challenge the Commission's analysis of its proposal or seek rehearing 
of its rejection. Instead, the Joint Commenters seek an acknowledgement 
from the Commission that, given the conclusions in the FEIS, the 
exercise of authority to mitigate is not warranted in this case. As we 
stated in Order No. 888 and the FEIS, mitigation is not warranted given 
the conclusions reached in the FEIS. The Commission also notes that we 
have thoroughly examined our legal authority in Order No. 888 and we 
find nothing in the arguments on rehearing that persuade us now to a 
different result. We have agreed to further examine our authority to 
engage in environmental mitigation through a Notice of Inquiry if EPA 
determines that the OTAG efforts are not successful. Therefore, it is 
unnecessary in this context to opine further in the abstract as to the 
scope of the Commission's mitigation authority.
    Because the PA Com and the Joint Commenters have raised no new 
arguments that were not thoroughly addressed in Order No. 888 and the 
FEIS, it is unnecessary to repeat here the thorough analysis of this 
issue set forth in those documents. The Commission declines to grant 
rehearing on this issue.
    Other Mitigation-Related Issues. VT DPS states that the Commission 
has given inadequate consideration to the possibility that the Rule may 
unnecessarily exacerbate environmental impacts and that the Commission, 
therefore, should adopt mitigation.
    This statement, which VT DPS fails to substantiate, is incorrect. 
The FEIS and the process which led to the conclusions contained therein 
fully consider the environmental impact of the Rule. VT DPS fails to 
identify any particulars in which the FEIS is deficient. VT DPS's 
disagreement appears to be a generalized dissatisfaction with the 
substantive conclusion reached by the FEIS that the Rule will not have 
significant environmental impacts.
    VT DPS next claims that the Commission's environmental review 
process has not facilitated the ability of affected parties to review 
all of the modeling assumptions. It also claims that other 
environmental reviews suggest that the Rule will have more serious 
NO<INF>X emissions consequences than acknowledged by the Commission.
    VT DPS again attacks the FEIS with a broad brush, but fails to 
identify ways in which the ability of parties to review modeling 
assumptions has been impeded. Likewise, it does not identify areas in 
which modeling assumptions have not been identified or any way in which 
its understanding of the FEIS has been hampered by the alleged 
unavailability of certain modeling assumptions. VT DPS is very late in 
raising such claims. The time to raise such issues is during the 
scoping process or in comments on the DEIS.
    It is unclear what other environmental reviews VT DPS is referring 
to or the ways in which those reviews allegedly suggest that the Rule 
will have more serious NO<INF>X emissions consequences than 
acknowledged by the Commission. Even if the unidentified studies reach 
different results than the FEIS this does not invalidate the 
conclusions contained in the FEIS. The mere fact of disagreement, even 
disagreement among experts in a given area, does not invalidate a 
study. <SUP>856
---------------------------------------------------------------------------

    \856\ See, e.g., Marsh v. Oregon Natural Resources Council, 490 
U.S. 360 (1989); Sierra Club v. Marita, 46 F.3d 606, 623-24 (7th 
Cir. 1995); Inland Empire Public Lands Council v. Schultz, 992 F.2d 
977, 981 (9th Cir. 1993).
---------------------------------------------------------------------------

    VT DPS next recommends that the Commission establish an ongoing 
monitoring program in consultation with environmental agencies. It 
states that a monitoring program would allow the Commission to take 
timely action to mitigate any unintended consequences of the Rule.
    An EIS is required to be prepared, when appropriate, prior to 
agency action. As the Supreme Court has stated, the moment at which an 
agency must have a final statement ready is the time at which it makes 
a recommendation or report on a proposal for federal action. <SUP>857 
There is no requirement that an agency continue to evaluate the 
environmental impacts of a project after it is implemented, 
particularly where, as here, the agency has determined that the 
proposal is not likely to have adverse environmental impacts.
---------------------------------------------------------------------------

    \857\ Kleppe v. Sierra Club, 427 U.S. 390 (1976).
---------------------------------------------------------------------------

    Moreover, as discussed extensively above, EPA's commitment to take 
action with regard to the underlying problems of the interstate 
transport of air pollutants provides a fuller measure of relief than 
that sought by VT DPS.
    The New York Attorney General claims that it is essential that FERC 
exercise any authority it may have to mitigate the environmental 
effects of the Rule because Congress has limited EPA's authority in 
this regard. The Attorney General also claims that EPA's proposal in 
its comments of February 20, 1996 on the DEIS to place a cap on 
NO<INF>X emissions would mitigate the effects of the Rule; it suggests 
basing

[[Page 12451]]

this system on the MOU. The Attorney General urges implementation of 
this system on the federal level pursuant to authority residing in EPA 
and/or FERC.
    We note first that Congress has made a full grant of authority to 
EPA to address the issue of the interstate transport of air pollution. 
As discussed extensively above, EPA has committed to address this 
issue, and to use its authority pursuant to the Clean Air Act if states 
are unwilling to address this issue cooperatively through the MOU 
process. Thus, EPA has committed to undertake the relief sought by the 
Attorney General. If EPA is unsuccessful, the Commission has pledged to 
assist in this effort as discussed above.

D. Emissions Standards Disparity

    Order No. 888 addresses claims that the Commission should ``level 
the playing field'' as to environmental standards. The argument was 
that unless the Commission imposes mitigation, competitors with 
``dirty'' generation will be favored over ``clean'' competitors. Those 
urging the adoption of measures to level the playing field argue that 
mitigation of environmental impacts has a direct relationship to 
ensuring that open access is implemented under terms of economic 
fairness for all utilities, and not merely those with current low-cost 
regulatory advantages.
    We responded to those arguments in Order No. 888 by noting that:

    [A]ll power generation technologies have different costs. For 
example, hydroelectric facilities which, like coal-fired facilities, 
may have environmental mitigation conditions imposed on them, may be 
quite expensive to build compared to gas or oil-fired generation, 
but their operating costs may be significantly lower. These cost 
differences may reflect the different costs of complying with 
mandated environmental requirements; the prudent costs of complying 
with such mandates may be reflected in rates.
    Indeed, sellers come to the power markets with a variety of 
advantages and disadvantages, many of which are the result of 
federal laws--for example, tax preferences, labor standards, and 
similar matters. In empowering the Commission to remedy undue 
discrimination and promote competition, Congress has not authorized 
the Commission to equalize the environmental costs of electricity 
production in order to ensure ``economic fairness.'' Such 
homogenization of competitors, or their costs, has never been a goal 
of the FPA.
* * * * *
    In short, the ``economic nexus'' urged by commenters advocating 
that the Commission undertake to regulate air emissions is 
inconsistent with the ``charge to promote the orderly production of 
plentiful supplies of electric energy'' envisioned by the FPA.
    We have exercised conditioning authority in the past only where 
necessary to ensure that jurisdictional transactions and rates do 
not result in anti-competitive effects, or are not unjust, 
unreasonable or unduly discriminatory or preferential. Thus, the 
conditions we have imposed have involved economic regulatory matters 
within our purview under the FPA. Any exercise of conditioning 
authority must, as the Supreme Court noted in NAACP, be directly 
related to our economic regulation responsibilities; EPA and the 
other commenters have not demonstrated such a nexus.
    This distinction is more evident when one considers the way in 
which we are authorized to treat the costs of environmental 
compliance. There are legitimate costs of environmental compliance 
that should be reflected in jurisdictional rates to the extent 
prudently incurred, just as the prudent costs of complying with, for 
example, occupational health and safety requirements designed to 
protect utility employees should be reflected in jurisdictional 
rates. This we are authorized to do and we routinely review and 
allow such costs. However, the fact that the costs of providing 
utility workers with a safe workplace are properly reflected in 
utilities' jurisdictional rates does not mean that we have authority 
to condition sellers' rates or customers' use of jurisdictional 
services on meeting safety regulations that are in the public 
interest. The same rationale applies to environmental matters 
related to the rule. [<SUP>858]
---------------------------------------------------------------------------

    \858\ FERC Stats. & Reg. at 31,890-91; mimeo at 740-43 
(footnotes omitted). The FEIS noted in this regard at page J-93 
that:
    Many factors cause generation sources to have differing costs. 
Some states impose taxes on generators that others do not. Some 
fuels are taxed differently than others (e.g., renewable generators 
such as wind power receive tax incentives that fossil generators do 
not while fossil fuels receive other tax advantages that renewables 
do not.) Such differences cannot be said to be unduly 
discriminatory, especially when they are sanctioned, or even 
required, by the actions of the Congress or state authorities. If 
the Commission attempted to ``level'' all of the ``playing fields'' 
it would be unable to judge any rate to be just and reasonable. 
Further, traditional rates are not determined through competitive 
processes but on a cost of service basis. Not all rates have to be 
determined to be competitive in order to be judged just and 
reasonable. * * *
---------------------------------------------------------------------------

Rehearing Requests

    Pennsylvania PUC. The PA Com asserts that the FEIS does not 
adequately address challenges posed by the Clean Air Act Amendments of 
1990. The PA Com contends that the Rule may shift power production from 
Pennsylvania plants with strong environmental controls to upwind plants 
with less stringent controls, and that prevailing climatic patterns may 
transport the increased pollution downwind. It states that mitigation 
is needed to prevent degradation of downwind air quality and the 
imposition of further costs and limits on downwind generation.
    The PA Com states that the Clean Air Act Amendments imposed 
stringent emission standards on Pennsylvania generation, but did not 
impose similar standards on neighboring states such as Ohio and West 
Virginia. It claims that the FEIS does not sufficiently consider these 
requirements. The PA Com concludes that implementing open access 
without mitigation will place Pennsylvania utilities at a competitive 
disadvantage, and that this result is inconsistent with the public 
policy goals of the Clean Air Act and the Federal Power Act. The PA Com 
also asserts that the Rule may discriminate against Pennsylvania 
utilities and the Pennsylvania coal industry, and that the combination 
of the Clean Air Act and Order No. 888 places Pennsylvania at a 
disadvantage in the competition for new industry and jobs.
    The PA Com claims that Order No. 888 may push states in the 
Northeast Ozone Transport Commission into repudiating the existing MOU. 
It claims that it is inconsistent for one federal purpose which is 
statutorily clear (i.e., clean air mandates established by the Clean 
Air Act Amendments) to be prejudiced by another federal purpose with 
only inferential statutory authority (i.e., open access under sections 
205 and 206 of the FPA).
    The PA Com asserts in this regard that Phase II of the MOU will 
require by 1999 a 55 percent reduction in NO<INF>X emissions in most of 
Pennsylvania and 65 percent (0.2 lbs/mmBTU) in the Philadelphia area. 
Title I of the Clean Air Act requires that the Northeast make 
reasonable progress towards attainment. If the inner zone of states 
comprising the Ozone Transport Commission do not achieve attainment, 
Phase III of the MOU will be implemented in 2003. Phase III requires a 
75 percent reduction in emissions (0.15 lbs/mmBTU) for the entire 
state. According to the PA Com, to meet Phase III requirements most 
Pennsylvania coal-fired stations will have to install Selective 
Catalytic Reduction technology at a capital cost of $2.3 to $3.5 
billion. It states that other Northeast states will be required to make 
expenditures that are much lower, and that states such as West Virginia 
and Ohio will not be subject to these requirements at all.
    New Jersey BPU. The NJ BPU poses a similar concern. It states that 
upwind power plants are designed to meet NO<INF>X emission standards 
which are substantially less restrictive than those required in New 
Jersey. The NJ BPU claims that this will have a two-fold impact--New 
Jersey air quality will be degraded through air transport and New 
Jersey utilities will be placed at a

[[Page 12452]]

significant cost disadvantage. The NJ BPU states that it is 
inconsistent to assert substantial incremental benefits associated with 
competition brought about by the Rule, while asserting that the Rule 
will not result in any change in the utilization of existing power 
plants.
    NJ BPU asserts that there are disparities in the electric industry 
among suppliers with regard to environmental impacts and costs, and 
that the Commission did not take this into account in determining the 
total economic benefit of a competitive wholesale generation market. It 
notes that the Commission may consider that it produced an economic 
benefit if the Rule enables a buyer in the Southeast to displace self-
generated 4-cent power with 3-cent power from the Midwest. The NJ BPU 
contends, however, that if emissions from the plants producing the 
electricity result in 1.5 cents worth of mitigation costs on a downwind 
state, an appropriate economic analysis would conclude that the 
transaction actually increases total costs. NJ BPU asserts that it was 
inappropriate for the Commission to focus on economic gains while 
leaving cost issues to be dealt with by other entities.
    NJ BPU recommends that the Commission adopt an integrated 
environmental, economic and energy policy approach which embraces the 
underlying principles in EPA's acid rain program. It states that the 
Commission should call for specific, significant and enforceable 
reductions in NO<INF>X emissions coupled with a market based trading 
program of emissions. It asserts that this approach would ensure a fair 
and competitive playing field at a fraction of the expected cost 
savings from the Rule.
    Joint Commenters. The Joint Commenters assert that the Commission 
has a duty under the FPA to mitigate undue preferences that affect 
competition in the wholesale power market. It concludes that this 
mandate must be applied here where implementation of open access 
policies without concurrent environmental mitigation will cause 
generation-owning utilities to face a discriminatory competitive 
situation.
    The Joint Commenters note that the Northeast is an ozone 
nonattainment area because of high levels of ambient ozone pollution, 
and is therefore subject to strict NO<INF>X reduction requirements. It 
states that regional utilities have invested significant sums in 
pollution reduction facilities and cleaner generation to meet legal 
requirements to reduce emissions. It contends that these utilities will 
be subject to additional NO<INF>X reduction requirements, thus 
increasing generation costs, if ambient ozone levels increase as a 
result of competition.
    The Joint Commenters contend that if open access increases 
emissions, utilities in the Northeast that have increased their 
generation costs to reduce air pollution will be required to bear 
additional costs to offset the impacts of increased upwind emissions. 
It states that the cost to Northeast utilities to offset additional 
NO<INF>X emissions will likely be substantially higher than the costs 
would be to upwind competitors to mitigate emissions at the source. It 
claims that offsetting the impacts of a 250,000 ton NO<INF>X increase 
in downwind nonattainment areas, where marginal NO<INF>X and volatile 
organic compound (VOC) control costs average about $3,800 per ton, 
could total $1 billion. On the other hand, mitigating the pollution 
increases at generation sources which currently operate with minimal 
environmental controls would cost about $500 per ton, or $130 million. 
The Joint Commenters assert that this cost differential will be hidden 
from the competitive market because Northeast generators will bear the 
cost.
    The Joint Commenters assert that this demonstrates that the 
wholesale bulk power market in the eastern United States is suffused 
with an existing undue preference that inordinately favors one category 
of competitors by allowing them to produce and sell power at a lower 
marginal cost. This preference exists today as a result of costs 
incurred in the past to meet Clean Air Act obligations; the FEIS 
demonstrates that Order No. 888 could worsen this situation as a result 
of increased sales from older, higher-emitting upwind coal generators.
    The Joint Commenters add that, aside from the competitive 
unfairness of this situation, the undue preferences will produce 
inefficiencies which distort investment decisions and increase the 
overall cost to produce electricity--the antithesis of what Order No. 
888 is meant to achieve. It asserts that these inefficiencies will 
occur in four ways:

    Sources in downwind nonattainment areas could have to spend 
hundreds of millions of dollars to address increased air pollution 
resulting from open access if polluting plants do not mitigate at 
the source. Thus, less efficient investments will be made to reduce 
air pollution and the overall cost of generating electricity will be 
higher than in a competitive market that is not distorted by 
discrimination.
    Order No. 888 could adversely impact the economic dispatch of 
generating sources under competitive conditions. In the absence of 
mitigation, generation from higher polluting upwind plants could 
displace generation from plants in the Northeast that operate more 
efficiently at the margin. As utilities in the Northeast are 
required to add more costly emission controls in response to 
interregional migration of air pollution, their operating costs will 
be driven up and may exceed the costs of less efficient plants which 
have avoided such controls. Thus, in the absence of mitigation, 
Order No. 888 may foster less efficient utilization of generating 
resources.
    Implementation of Order No. 888 without mitigation may distort 
the market for future generation capacity. If older, more highly-
polluting plants can shift the environmental cost of production to 
other wholesale generators, they are likely to expand their output 
to address market needs, thus reducing the demand for more 
efficient, clean-burning generating facilities.
    Transmission from the Midwest to the East is often heavily 
constrained. Consequently, a distorted price signal to increase 
generation in the Midwest would exacerbate existing constraints and 
improperly stimulate the construction of new transmission capacity 
to support additional interregional transactions.

The Joint Commenters conclude that the Commission has an obligation to 
exercise its authority in non-arbitrary manner, particularly when 
acting to prevent undue discrimination.
    Finally, the Joint Commenters disagree with the Commission's 
response to this issue in Order No. 888. It asserts that the Commission 
and the courts have found in the ``price squeeze'' context that the 
Commission has authority to remedy anti-competitive discrimination, 
even when it is caused by regulatory practices of others over which it 
and its regulated public utilities have no control. Second, the 
Commission has the authority and responsibility to address 
environmental issues that directly affect and have a nexus to its 
section 205 and 206 responsibilities. Third, if the competitive market 
that the Commission wishes to create will not operate fairly or 
efficiently, the Commission has a duty to consider whether it should go 
forward at all if it believes it does not have the power to remedy 
important adverse competitive consequences.

Commission Conclusion

    Congress has empowered the Commission to remedy undue 
discrimination and promote competition; it has not authorized the 
Commission to equalize the environmental costs of electricity 
production in order to ensure ``economic fairness.'' Homogenization of 
competitors, or their costs, has never been a goal of the FPA.
    Action in Order No. 888 to remedy undue discrimination in access to 
the monopoly owned transmission wires

[[Page 12453]]

that control whether and to whom electricity can be transported in 
interstate commerce does not require action by the Commission to cure 
all competitive differences between participants in the utility 
marketplace. This is particularly true where the disparities arise 
because Congress has established policies with regard to competing 
issues of national significance and charged other agencies of the 
federal government with implementing those policies. The assertion that 
the Commission must eliminate any competitive disadvantage arising from 
congressionally mandated policies, including the vital national 
policies set forth in the Clean Air Act, before it can act to remedy 
undue discrimination and encourage competition in the electric utility 
industry is in error.
    Furthermore, as noted above, the analysis reflected in the FEIS 
refutes the claim that the Rule will result in significant 
environmental impacts. Thus, there is no basis in any event to support 
requests that the Commission ``level'' the playing field.
    Recounted briefly, those findings show that, without the Rule, 
NO<INF>X emissions are expected to decline until at least the year 
2000. Thereafter, again without the Rule, NO<INF>X emissions are 
expected to increase steadily through the year 2010. The extent of the 
decrease and increase will be largely determined by the relative prices 
of natural gas and coal.
    The analysis also demonstrates that the Rule will not in any 
significant respect affect these overall trends. The analysis shows 
that if the Rule results in efficiency gains in the electric industry 
that favors the use of natural gas as a fuel, the effect will be 
slightly beneficial; total NO<INF>X emissions will be reduced overall 
by about two percent nationwide below what would otherwise be expected 
to occur. If the Rule results in efficiency gains that favor the use of 
coal as a fuel, the Rule is expected to increase NO<INF>X emissions 
approximately one percent above what would otherwise be expected to 
occur.
    Even analyzing the highly unlikely frozen efficiency case, the 
analysis demonstrates that the impacts of the Rule will not be great 
and will not vary significantly from those projected by staff under the 
assumptions discussed above. This study, utilizing a combination of 
assumptions geared to demonstrate the greatest impact the Rule might 
have on increased NO<INF>X emissions, produced little in the way of 
environmental consequences associated with the Rule. Under these 
extreme (and unlikely) conditions, there would still be a net decrease 
in NO<INF>X emissions until at least the year 2000, albeit a smaller 
decrease than in the base cases. Comparing projections of emissions for 
the same years, emissions would be higher than the base cases only by 
two percent in 2000 and three percent in 2005. It is only in the year 
2010, assuming these improbable scenarios, that NO<INF>X emissions 
associated with the Rule would be higher than the base case by even 
five percent.
    All told, this analysis demonstrates that the Rule will affect air 
quality slightly, if at all, and that the environmental impacts are as 
likely to be beneficial as negative. This is true under scenarios 
contrived to maximize emissions under circumstances that the Commission 
believes to be highly unlikely. This is also true in the near to mid-
term. Assuming that any environmental impacts occur, they are years in 
the future and may well be beneficial.
    Thus, contrary to the position taken by those seeking to have the 
Commission impose mitigation, the Rule will not result in impacts 
requiring mitigation to level the playing field.
    Moreover, as also noted above, EPA has committed to address the 
existing NO<INF>X transport issue, including the contribution of the 
Rule, if any, to those impacts. It must be emphasized in this regard 
that the Northeast has experienced significant air pollution problems 
for many, many years. Much of this pollution is generated by activities 
within the affected states and within the affected region; the problem 
is exacerbated somewhat by the airborne transport of pollutants from 
upwind areas, including pollutants resulting from the generation of 
electricity that will occur regardless of any future increase in 
generation that might result from implementation of the Rule.
    Put differently, the pollution problems in the individual states 
and in the Northeast in general result primarily from economic 
activities within those states. The airborne transport of pollutants, 
including pollution resulting from existing electric generation, adds 
to the existing problem to some degree. The analysis in the FEIS 
demonstrates that open access may increase the amount of upwind 
generation by some small increment, and thus increase the downwind 
NO<INF>X levels by an even smaller incremental amount. On the other 
hand, depending on the future competitive position of natural gas 
versus coal, a situation over which the Commission has no control, the 
Rule may decrease the amount of pollution that would otherwise exist 
and thus decrease downwind pollution. In any event, the Rule will 
affect existing trends slightly, if at all.
    In recognition of the situation described above, which again is 
likely to be affected only very slightly, if at all, by the Rule, EPA 
has committed to address the overall issue of NO<INF>X emissions as 
part of a comprehensive program developed by EPA and the states. EPA 
has committed to use its authority under the Clean Air Act to 
successfully complete the OTAG process. EPA states that it will, if 
necessary, establish a NO<INF>X cap-and-trade program for the OTAG 
region through Federal Implementation Plans if some states are unable 
or unwilling to act in a timely manner.
    As discussed in the FEIS, and as noted above, OTAG has efforts 
underway to develop responses to this problem. For example, OTAG 
intends to submit its findings regarding ozone transport patterns and 
its recommendations for mitigation of ozone transport to EPA by April 
or May 1997. If this process is less than fully successful, the Clean 
Air Act authorizes EPA to act in a relatively short time-frame to 
address this problem. EPA has committed to exercise this authority to 
address the problem.
    It must be emphasized that EPA has stated its intent to address the 
problem regardless of the effects of the Rule. Even if the Rule results 
in environmental impacts, those incremental impacts will be addressed 
as part of the comprehensive NO<INF>X regulatory developed by EPA in 
conjunction with the states.
    Thus, EPA has committed to undertake the mitigation sought by the 
PA Com, NJ BPU and Joint Commenters. The Commission has stated its 
intent to participate in this process as discussed above. This result 
negates claims that implementing open access without mitigation will 
place downwind utilities and the Pennsylvania coal industry at a 
competitive disadvantage. Accordingly, the requests that the Commission 
impose mitigation measures to ``level'' the environmental playing field 
are denied.

E. Short-Term Consequences of the Rule

    The FEIS projects future electric powerplant emissions under a 
range of assumptions without the Rule (base cases). These results are 
then compared to what electric powerplant emissions are likely to be 
under corresponding assumptions with the Rule in place (Rule 
scenarios). The study utilizes three reporting years: 2000, 2005, and 
2010. These reporting years were chosen because they cover a reasonable 
time frame for the study. Beyond 2010, the

[[Page 12454]]

projections are dependent on too many unforeseeable factors to be 
meaningful.<SUP>859
---------------------------------------------------------------------------

    \859\ FEIS at ES-9, 3-1.
---------------------------------------------------------------------------

    Although the effects of the Rule will begin to occur when the final 
Rule is issued, the effects should develop gradually over time. 
Measurable effects are expected to be clearly observable by the year 
2000, though not necessarily fully complete.<SUP>860
---------------------------------------------------------------------------

    \860\ Id. at 3-1.
---------------------------------------------------------------------------

    The FEIS analysis of the Rule scenarios shows that NO<INF>X 
emissions are expected to decrease significantly between 1993 and 2000. 
The Competition-Favors-Gas Scenario demonstrates that the Rule will 
reinforce decreases already present in the base case. Thus, the Rule 
will enhance underlying environmental improvements. While the 
Competition-Favors-Coal Scenario demonstrates small emissions 
increases, NO<INF>X emissions nonetheless continue to decrease from 
1993 to 2000. A similar trend is also seen on a regional basis. The 
Rule does not alter the basic pattern of environmental 
improvement.<SUP>861
---------------------------------------------------------------------------

    \861\ Id. at 5-15.
---------------------------------------------------------------------------

Rehearing Requests

    New Jersey BPU. The NJ BPU claims that the FEIS fails to recognize 
possible short-term effects the Rule may have on existing ozone 
problems in the Northeast, and that the failure to address short-term 
consequences is of particular importance to nonattainment states who 
must meet Clean Air Act attainment dates in 1996 and 1999.
    Joint Commenters. The Joint Commenters claim that by examining the 
period between 2000 and 2010, the FEIS fails to analyze near-term 
impacts and the need for a short-term mitigation strategy. Joint 
Commenters note that the Rule will be implemented almost immediately, 
and that changes in generation plant utilization that give rise to the 
greatest environmental concerns may occur very quickly.
    The Joint Commenters are concerned that the FEIS does not consider 
how projected environmental effects prior to 2000 would impact air 
quality and Clean Air Act attainment deadlines. The Joint Commenters 
contest the conclusion that utility NO<INF>X emissions will decline 
between 1993 and 2000. It states that emissions will increase each year 
between 1993 and 2000 except in 1996 and 2000, when large NO<INF>X 
reductions will be implemented pursuant to the Clean Air Act. The Joint 
Commenters also contend that it is irrelevant whether clean air 
programs will cause overall emissions to be lower in 2000 than they 
were in 1993; the relevant question is whether emissions will be higher 
with Order No. 888 than without it.
    The Joint Commenters contend that the data presented in the FEIS 
for the year 2000 suggest that, if the Rule is considered in isolation, 
there will be potentially significant short-term emissions increases in 
the period 1996-2000. It states that the FEIS indicates that 
implementation of the Rule under the Competition-Favors-Coal Scenario 
with expanded transmission will lead to an additional 132,000 tons of 
NO<INF>X emissions in 2000 compared with the frozen efficiency 
reference case. It contends, assuming a linear increase, that this 
means there could be an additional 75,000, 94,000 and 113,000 tons of 
NO<INF>X emissions as a result of the Rule in 1997, 1998, and 1999, 
respectively.

Commission Conclusion

    The Joint Commenters' claims that implementation of the Rule will 
lead to an additional 132,000 tons of NO<INF>X emissions in the year 
2000 in incorrect. As is the case with regard to its assertion above 
that the Rule will result an additional 315,000 tons of NO<INF>X 
emissions in 2010, this impact was derived by selectively choosing 
numbers from the FEIS, comparing two sensitivity cases designed to be 
unrealistically low and high extremes. The low emissions case is the 
frozen efficiency case that represents a complete reversal of current 
industry and regulatory trends that are occurring without the Rule. The 
high emissions case represents an increase in transmission capacity 
that cannot reasonably be ascribed to the Rule. As stated in the FEIS, 
these cases were selected to examine the sensitivity of FEIS findings 
to certain extreme assumptions maintained by commenters and are not the 
appropriate cases for determining potential environmental impacts from 
the Rule.
    Moreover, we note that the Joint Commenters reference increases 
from the Rule without noting equally likely decreases. Even with the 
lower emissions resulting from the unrealistic frozen efficiency case, 
the FEIS finds decreases in emissions from the Rule when competitive 
forces lead to greater efficiency for natural gas generation compared 
to coal.
    The Commission has analyzed the Rule and found that its impacts 
will be insignificant. We also note that even if the Rule were to 
result in short-term emission increases, EPA has signaled its 
willingness to address the transport of pollutants in a timely fashion. 
As discussed above, EPA has concluded that any emissions increases 
associated with the Rule should be addressed as part of a comprehensive 
NO<INF>X emissions control program developed by EPA and the states 
under mechanisms available under the Clean Air Act. This approach 
includes support for OTAG efforts to develop emissions reduction 
strategies. OTAG plans to submit its findings and mitigation 
recommendations to EPA by April or May 1997. As discussed above, EPA 
has issued a notice of intent to adopt by summer 1997 a rule that would 
require state implementation plan measures to ensure that emission 
reductions are achieved as needed to prevent significant transport of 
ozone pollution across state boundaries in the Eastern United States. 
EPA is contemplating establishing deadlines for state implementation 
plan submittals ranging from six months to 18 months following the date 
of publication of its notice of final rulemaking.
    The instant Rule will affect the existing NO<INF>X transport issue 
very little, if at all. As stated in Order No. 888, the Rule is not the 
appropriate vehicle for resolving this debate. The appropriate 
regulatory mechanism for addressing the overall NO<INF>X problem, 
including emissions from electric utility generating plants, is a 
NO<INF>X emissions cap and allowance trading scheme along the lines of 
that developed by the Congress under the Clean Air Act for SO<INF>2 
emissions. As noted, EPA has committed to implement this approach. Even 
if there are slight environmental impacts associated with the Rule, 
they are better and more effectively addressed as part of a 
comprehensive NO<INF>X regulatory program.

G. Cost Benefit Analysis

    ``The legal and policy cornerstone'' of Order No. 888 ``is to 
remedy undue discrimination in access to the monopoly owned 
transmission wires that control whether and to whom electricity can be 
transported in interstate commerce.'' <SUP>862 As reiterated in the 
FEIS, the purpose of the Rule is to increase access to non-
discriminatory transmission services and thereby increase competition 
in wholesale electric markets.<SUP>863
---------------------------------------------------------------------------

    \862\ FERC Stats. & Regs. at 31,634; mimeo at 1.
    \863\ FEIS at ES-13 through ES-16.
---------------------------------------------------------------------------

    The FEIS states that the Rule will give wholesale power customers a 
greater opportunity to obtain competitively priced electricity. 
Competition will create benefits through better use of existing assets 
and institutions, new market mechanisms, technical innovation, and less 
rate distortion.

[[Page 12455]]

Only the first--better use of existing assets and institutions--was 
estimated quantitatively: approximately $3.8 to $5.4 billion per year. 
The FEIS also discusses other benefits that cannot be quantified but 
may be large. Based on the experience of, for example, the natural gas 
and telecommunications industries, the Commission opined that the other 
three are likely to increase industry efficiency--and benefits--
substantially.<SUP>864
---------------------------------------------------------------------------

    \864\ The discussion of the economic benefits of the Rule in 
found in the FEIS at ES-13 through ES-16 and 5-64 through 5-75.
---------------------------------------------------------------------------

    As described elsewhere in this order, the FEIS also discusses 
extensively possible environmental effects (i.e., costs) of the Rule. 
It concludes that the Rule could raise or lower national emissions 
slightly, but will not have a significant effect on the environment.

Rehearing Requests

    The Joint Commenters contend that the analysis of projected 
benefits from the Rule appears to be inadequately substantiated and 
uses assumptions that are inconsistent with those used to reach a 
finding of no significant impact on environmental issues. Although 
Joint Commenters do not challenge the conclusion that Order No. 888 
will result in economic benefits, it states that the benefits 
identified in the FEIS are inadequately substantiated and do not 
reflect a balanced analysis. It claims that courts have held that when 
economic development is the selling point or raison d'etre of an action 
NEPA requires the agency to provide a specific comparison of economic 
benefits versus environmental costs. It concludes that the analysis of 
the economic benefits of Order No. 888 is tipped in favor of benefits, 
especially when contrasted with the analysis of projected environmental 
impacts.
    Joint Commenters state that the conclusion that benefits will range 
from $3.76 to $5.37 billion per year is not properly documented and 
cannot be relied upon as justification for implementing the Rule 
without mitigation. It contends that the Commission is counting 
benefits from changes that are unrelated to the Rule, such as benefits 
resulting from higher plant availability factors. Joint Commenters 
claim that this assertion appears to be inconsistent with industry 
reactions to competition to date. The same is true of planning reserve 
margins. It states that key assumptions used to define the operating 
savings, particularly fuel price assumptions, are unreasonable. It adds 
that these savings are the ones that give rise to adverse environmental 
effects due to increased utilization of existing low-cost coal 
generation. Therefore, it is inappropriate to count these economic 
benefits without examining the offsetting environmental costs, which 
increase as the level of the asserted benefits increase.
    Finally, Joint Commenters assert that the FEIS does not address 
potential costs associated with implementing the Rule. These include 
costs to the Northeast and other regions of additional environmental 
compliance and the impact on public health of additional pollution; 
socioeconomic costs associated with utility downsizing; potential 
adverse effects on nuclear power plant operations from competition; or 
potential regulatory costs associated with compliance with Order No. 
888. Thus, Joint Commenters conclude that the FEIS does not provide a 
basis for calculating the net benefits of Order No. 888. It also states 
that the FEIS does not provide a basis for concluding that the 
potential savings will exceed the additional costs associated with 
increased use of coal generation without mitigation.

Commission Conclusion

    The fulcrum of Joint Commenters' challenge is its claim that when 
economic development is the selling point of a proposed action, NEPA 
requires the agency to provide a specific comparison of economic 
benefits versus environmental costs. The Joint Commenters do not 
challenge the conclusion that the Rule will result in economic 
benefits. Rather, it claims that the benefits identified in the FEIS 
are not adequately substantiated and do not reflect a balanced analysis 
of benefits versus costs. This argument is made to further the claim, 
asserted by Joint Commenters in various forms, that the Commission must 
impose mitigation to ``level'' the playing field.
    The Joint Commenters' argument misapprehends the purpose of Order 
No. 888, the role a cost-benefit analysis plays in an EIS, and the 
reasons for the Commission's discussion of the economic benefits of the 
Rule.
    The purpose of the Rule is not to foster economic development, 
although the Commission anticipates that this will be a salutary effect 
of open access. The purpose of the Rule is to promote competition in 
the wholesale bulk power markets by remedying undue discrimination in 
access. The fact that the Rule will create benefits through better use 
of existing assets and institutions, new market mechanisms, technical 
innovation, and less rate distortion is a consequence rather than the 
purpose of the Rule.
    The Joint Commenters also mistake the role a cost-benefit analysis 
plays in an EIS. The CEQ regulations implementing NEPA set forth the 
requirements pertaining to a cost-benefit analysis at 40 CFR 1502.23 
(1996):

    If a cost-benefit analysis relevant to the choice among 
environmentally different alternatives is being considered for the 
proposed action, it shall be incorporated by reference or appended 
to the statement as an aid in evaluating the environmental 
consequences. To assess the adequacy of compliance with section 
102(2)(B) of the Act the statement shall, when a cost-benefit 
analysis is prepared, discuss the relationship between that analysis 
and any analyses of unquantified environmental impacts, values, and 
amenities. For purposes of complying with the Act, the weighing of 
the merits and drawback of the various alternatives need not be 
displayed in a monetary cost-benefit analysis and should not be when 
there are important qualitative considerations. In any event, an 
environmental impact statement should at least indicate those 
considerations, including factors not related to environmental 
quality, which are likely to be relevant and important to a 
decision.

Thus, the function of a cost-benefit analysis is to assist in the 
choice among environmentally different alternatives. As discussed 
above, the Commission's recitation in the FEIS of the anticipated 
economic benefits of the Rule is not undertaken to assist in the choice 
among environmental different alternatives. The FEIS discusses the 
expected economic benefits of the Rule in a broader context, noting 
that ``[t]he most important socioeconomic effect of the proposed rule 
is expected to be potentially large benefits to ratepayers and to the 
economy as a whole.'' <SUP>865
---------------------------------------------------------------------------

    \865\ FEIS at 5-64.
---------------------------------------------------------------------------

    The authorities cited by the Joint Commenters do not alter this 
conclusion. The Commission is not using the benefits of the Rule as a 
selling point to go forward with the action while ignoring 
disadvantages that might flow from it. The FEIS fully examines the 
impacts of the Rule and concludes that implementation of the Rule will 
not result in adverse environmental consequences. The Joint Commenters 
disagreement is with this substantive conclusion, not with the alleged 
failure to conduct a cost-benefit analysis. Their disagreement does not 
mean, however, that the Commission has ignored the disadvantages that 
Joint Commenters assert would flow from the Rule. In brief, as 
discussed throughout the FEIS, Order No. 888, and this order on 
rehearing, the Commission has examined the impacts of the Rule and

[[Page 12456]]

concluded that it will not result in environmental harms.
    Thus, even under the broadest possible interpretation of the cost-
benefit analysis requirement, the Commission has evaluated the benefits 
of the Rule against its impacts and concluded that the benefits are 
likely to be significant and that the impacts are likely to be 
insignificant.<SUP>866
---------------------------------------------------------------------------

    \866\ In point of fact, the overall thrust of the FEIS is to 
analyze and discuss the projected costs of the Rule. The discussion 
of the projected benefits of the Rule comprise a tiny fraction of 
that discussion. The Joint Commenters dissatisfaction with the 
results of the analysis does not mean that the projected impacts of 
the Rule were not discussed in full.
---------------------------------------------------------------------------

    The D.C. Circuit rejected the underlying argument advanced here by 
the Joint Commenters in Public Utilities Commission of the State of 
California v. FERC, 900 F.2d 269 (D.C. Cir. 1990). There, California 
contended that the Commission did not comply with NEPA in granting an 
Optional Expedited Certificate (OEC) permitting construction of a 
natural gas pipeline. California argued that the Commission could not 
have balanced the adverse environmental effects against the need for 
the project because under the OEC procedures it made no particularized 
inquiry into the economic benefits of the pipeline. The court responded 
that:

    Two of our cases speak of a NEPA requirement that ``responsible 
decisionmakers *  *  * fully advert[] to the environmental 
consequences'' of a proposed action and ``decide[] that the public 
benefits *  *  * outweigh[] the[] environmental costs.'' Illinois 
Commerce Comm'n v. ICC, 848 F.2d 1246, 1259 (D.C.Cir.1988); Jones v. 
District of Columbia Redevelopment Land Agency, 499 F.2d 502, 512 
(D.C.Cir.1974). Though the Commission engaged in an ``individualized 
consideration and balancing of environmental factors,'' as required 
by Calvert Cliffs' Coord. Comm. v. United States Atomic Energy 
Comm'n, 449 F.2d 1109, 1115 (D.C.Cir.1971), its evaluation of the 
nonenvironmental aspects of the pipeline was not individualized. As 
to them the Commission stated that ``the interests of the public 
articulated in our adoption of the optional certificate process 
[i.e., Order No. 436] outweigh, on balance, the relatively 
insubstantial environmental harm which will result from a properly 
mitigated WyCal Pipeline.'' Mojave Pipeline Co., 46 FERC at 61,168 
(emphasis added).
    California's insistence on a particularized assessment of non-
environmental features finds no support in the statutory language. 
See NEPA Sec. 102, 42 U.S.C. Sec. 4332 (requiring the agency to 
consider a variety of environmental, not economic, factors). Its 
theory would disable any number of efforts at streamlining the 
resolution of regulatory issues that have nothing to do with the 
environment. An agency's primary duty under the NEPA is to ``take[] 
a 'hard look' at environmental consequences.'' Kleppe v. Sierra 
Club, 427 U.S. 390, 410 n. 21, 96 S.Ct. 2718, 2730 n. 21, 49 L.Ed.2d 
576 (1976). We will not extend that statute well beyond its realm so 
as to create unnecessary conflicts with others. [<SUP>867]

    \867\ Public Utilities Commission, 900 F.2d at 282 (brackets, 
ellipses, and emphasis in original).
---------------------------------------------------------------------------

    Thus, an agency need not conduct a particularized assessment of the 
nonenvironmental features of a proposal, in particular its economic 
benefits or costs. The Commission nonetheless examined the potential 
costs of the Rule and determined that those costs will be very small 
and may be positive instead of negative in any event. The Commission 
has also examined the benefits of the project and concluded that it 
will have substantial benefits. Accordingly, the request for rehearing 
is denied.

H. Socioeconomic Impacts

    The FEIS examines the socioeconomic impacts of the Rule, including 
whether the Rule will result in regional shifts in economic activity 
(especially electric generation and coal mining).<SUP>868 The analysis 
demonstrates that an effect of a more competitive industry may be 
increased use of existing electric generating facilities. Consequently, 
it seems likely that those who supply fuel to existing plants could see 
a higher demand for their output as a result of the Rule. The FEIS 
notes that this might not be true in all places, however, if factors 
such as changes in environmental standards work in the opposite 
direction. The FEIS does not attempt to measure local or site-specific 
impacts given the speculative nature of such impacts.
---------------------------------------------------------------------------

    \868\ FEIS at 5-64 and 5-75 through 5-76.
---------------------------------------------------------------------------

    The FEIS also notes that open access could lead to changes in 
employment patterns, but concludes that it is highly uncertain, 
however, which changes are likely to result from restructuring.<SUP>869 
The FEIS notes that some changes should lead to cost reductions that 
will tend to increase jobs in other industries, as well as lower rates 
for other consumers. Lower power bills can make other industries more 
competitive and lead them to increase employment.
---------------------------------------------------------------------------

    \869\ Id. at 5-75 through 5-76.
---------------------------------------------------------------------------

    The FEIS also notes that the Rule is only part of the restructuring 
currently affecting the industry. Employment in traditional utilities 
has fallen in recent years. Developments at the state and federal 
levels will increase competition in the industry even without the Rule. 
Given the highly uncertain nature of future developments in the 
electric industry and the complex, dynamic economic issues involved, 
the FEIS concludes that any quantitative estimate of changes in 
employment (or even the direction of change) would be highly 
speculative.

Rehearing Requests

    The PA Com claims that socioeconomic impacts that may result from 
regional economic shifts occurring as a result of the Rule are not 
adequately discussed in the FEIS. It states that Order No. 888 
contemplates a reduction in the amount of coal-fired generation, and 
that if Pennsylvania generation is shut-down or dispatched less often 
in favor of generation that is not subject to the same environmental 
costs and requirements, less Pennsylvania coal will be mined.
    The PA Com states that Pennsylvania produces 60 million tons of 
coal a year, most of which is purchased by Pennsylvania electric 
utilities. It alleges that the Pennsylvania coal industry provides 
9,200 direct mining jobs and 9,500 support service jobs. Coal sales 
contribute $1.5 billion to the Pennsylvania economy each year and 
provide an annual payroll of $600 million. The PA Com adds that if coal 
production declines, the state may curtail efforts to reclaim abandoned 
mines and coal refuse piles.
    The PA Com also contends that social obligations now borne by 
transmission owning utilities--demand side management programs, 
integrated resource planning, low-income assistance programs, and 
federal environmental mandates--have an impact upon price and the 
market for power, and that utilities might view these obligations as an 
impediment to competition. It claims that third parties who wish to use 
the transmission system may balk if they are required to contribute to 
those social goals.
    Finally, the PA Com claims that functional unbundling, open access 
on a comparability basis, and increased competition may impact 
reliability of service. It states that it is concerned that reliability 
is subordinate to economic concerns, and that if reliability is not an 
articulated foundation of FERC actions, system reliability may suffer. 
It concludes that the FEIS assumes that reliability will be enhanced by 
open access, but that this assumption is not adequately explained.

Commission Conclusion

    The PA Com's concerns as to the alleged socioeconomic impacts of 
the Rule are based on a series of tenuous economic ``what-ifs.'' It 
assumes that the Rule will result in a reduction in Pennsylvania 
generation. It assumes from this that less coal will be mined in

[[Page 12457]]

Pennsylvania and that Pennsylvania will suffer adverse economic 
consequences. It then assumes that this might lead Pennsylvania to 
curtail efforts to reclaim abandoned surface and strip mines. No basis 
has been shown to support the elements in this chain of assumptions. 
The effects Pennsylvania fears are simply too speculative to assess at 
this time.
    Moreover, the PA Com's concerns stem from the postulated economic 
impacts of the Rule rather than from the alleged impact of the Rule on 
the physical environment. Thus, its concerns are not proper for 
consideration in an EIS. The CEQ states that socioeconomic impacts 
alone do not warrant study in an EIS.<SUP>870 The CEQ also states that 
an agency must make reasonable efforts in preparing an EIS to acquire 
relevant information concerning socioeconomic impacts when economic or 
social and natural or physical environmental effects are 
interrelated.<SUP>871 If such effects are not interrelated, they need 
not be considered. In this case, the PA Com's concerns stem from what 
it anticipates will be the economic impact of the Rule on Pennsylvania, 
and not from the natural or physical environmental impacts of the Rule. 
Thus, these concerns are not proper for consideration in an 
EIS.<SUP>872
---------------------------------------------------------------------------

    \870\ The CEQ regulations, 40 CFR 1508.14 (1996), state that 
``economic or social effects are not intended by themselves to 
require preparation of an environmental impact statement.'' See also 
Panhandle Producers & Royalty Owners Association v. Economic 
Regulatory Administration, 847 F.2d 1168, 1179 (5th Cir. 1988); 
Olmstead Citizens for a Better Community v. United States, 793 F.2d 
201, 205 (8th Cir. 1986).
    \871\ The CEQ regulations, 40 CFR 1508.14 (1996), provide that 
``[w]hen an environmental impact statement is prepared and economic 
or social and natural or physical environmental effects are 
interrelated, then the environmental impact statement will discuss 
all of these effects on the human environment.'' This limitation has 
been read very strictly. In Stauber v. Shalala, 895 F.Supp. 1178, 
1194 (W.D.Wis.1995), for example, the court responded to a claim 
that a proposed action would cause both environmental and 
socioeconomic harms and that for this reason an EIS was necessary. 
The court found that:
    This assertion is insufficient to satisfy the 
``interrelatedness'' requirement of Sec. 1508.14. I read 40 C.F.R. 
Sec. 1508.14 to mean that it is only after an agency determines that 
the socioeconomic impact of the proposed agency action is likely to 
cause environmental harms itself that the agency needs to discuss 
the socioeconomic effects in the environmental impact statement. See 
Breckinridge v. Rumsfield, 537 F.2d 864, 866 (6th Cir.1976) 
(accord), cert. denied, 429 U.S. 1061, 97 S.Ct. 785, 50 L.Ed.2d 777 
(1977). This reading fully comports with the plain language of the 
regulation. * * *
    \872\ It is interesting to note in this regard that Pennsylvania 
recently adopted electric restructuring legislation of its own 
establishing retail wheeling. It thus became the fourth state in the 
Northeast to do so; the others are Massachusetts, Rhode Island, and 
New Hampshire. The legislation was described by the Governor of 
Pennsylvania as creating a ``critical competitive advantage'' for 
Pennsylvania. The Energy Daily, December 4, 1996.
---------------------------------------------------------------------------

    The approach to such issues is perhaps best symbolized by the 
Supreme Court's decision in Metropolitan Edison Co. v. People Against 
Nuclear Energy, 460 U.S. 766 (1983). In that case, People Against 
Nuclear Energy (PANE) contended that NEPA required the Nuclear 
Regulatory Commission to consider whether restarting the Three Mile 
Island-1 nuclear reactor after the accident at the Three Mile Island-2 
reactor would ``cause both severe psychological health damage to 
persons living in the vicinity, and serious damage to the stability, 
cohesiveness, and well-being of the neighboring communities.'' <SUP>873 
The court rejected this argument:

    \873\ Metropolitan Edison Co., 460 U.S. at 769. PANE also 
asserted that NEPA required consideration of ``[t]he perception, 
created by the accident, that the communities near Three Mile Island 
are undesirable locations for business or industry, or for the 
establishment of law or medical practice, or homes compounds the 
damage to the viability of the communities.'' Id. at 770 n.2.
---------------------------------------------------------------------------

    The theme of Sec. 102 is sounded by the adjective 
``environmental'': NEPA does not require the agency to assess every 
impact or effect of its proposed action, but only the impact or 
effect on the environment. If we were to seize the word 
``environmental'' out of its context and give it the broadest 
possible definition, the words ``adverse environmental effects'' 
might embrace virtually any consequence of a governmental action 
that someone thought ``adverse.'' But we think the context of the 
statute shows that Congress was talking about the physical 
environment--the world around us, so to speak. NEPA was designed to 
promote human welfare by alerting governmental actors to the effect 
of their proposed actions on the physical environment.

* * * Thus, although NEPA states its goals in sweeping terms of 
human health and welfare, those goals are ends that Congress has 
chosen to pursue by means of protecting the physical environment. 
[<SUP>874]

    \874\ Id. at 772-73 (emphasis in original) (footnote omitted). 
The continuing validity of the argument that socioeconomic effects 
are to be considered in an EIS if the federal action has a primary 
impact on the natural environment is doubtful. The court in Olmsted 
Citizens for a Better Community v. United States, 793 F.2d 201, 206 
(8th Cir. 1986) stated that:
    [I]t is unlikely that such a distinction survives the recent 
Supreme Court holding in Metropolitan Edison. That decision, as 
discussed above, was based on congressional intent, and there is no 
suggestion that Congress contemplated that the process it designed 
to make agencies aware of the consequences of their actions with 
regard to the physical environment would be converted into a process 
for airing general policy objections anytime the physical 
environment was implicated. Such a rule would divert agency 
resources away from the primary statutory goal of protecting the 
physical environment and natural resources. * * *
---------------------------------------------------------------------------

    Even though it was not incumbent upon it to do so, the Commission 
analyzed the concerns raised by the PA Com to the extent it was 
practicable to do so. The impacts of the Rule on future levels of coal-
fired generation in Pennsylvania or on employment in a specific 
geographic area or in a specific economic sector are influenced by a 
virtually unlimited roster of other factors, and thus are too 
speculative to be useful.

I. Coastal Zone Management Act

    Order No. 888 found that the Rule does not constitute a federal 
activity subject to compliance with the Coastal Zone Management Act, 16 
U.S.C. Sec. 1451 et seq. (CZMA). <SUP>875 Order No. 888 concluded that:

    \875\ FERC Stats. & Regs. at 31,895; mimeo at 754.
---------------------------------------------------------------------------

    Connecticut has in any event waived its right to request a 
consistency determination for the Commission's rulemaking. 
Connecticut's coastal management program's list of federal agency 
activities likely to require a consistency determination does not 
(for good reason) describe rulemakings of this kind, and the rule 
will not ``result in a significant change in air or water quality 
within the management area'' (the program's catch-all category). In 
addition, Connecticut did not notify the Commission of its 
conclusion that the Rule requires a consistency determination until 
well after 45 days from receipt of several notices of the rulemaking 
proceeding. Consequently, pursuant to 15 CFR 930.35(b), Connecticut 
has in any event waived its right to request a consistency 
determination for this rulemaking. [ <SUP>876]
---------------------------------------------------------------------------

    \876\ Id. at 31,895-96; mimeo at 755-56 (footnote omitted).
---------------------------------------------------------------------------

Rehearing Requests

    The Connecticut Department of Environmental Protection (Connecticut 
DEP) requests that the Commission determine whether Order No. 888 is a 
federal activity requiring a coastal consistency determination, 
determine whether the Rule is consistent with Connecticut's coastal 
management plan (CMP), and consider the impacts that promoting 
competition and altering transmission and generation patterns may have 
on water quality in the Long Island Sound. The Connecticut DEP also 
requests that the Commission mitigate potential increases in nitrogen 
and sulphur oxide emissions occurring as a result of the Rule.

Commission Conclusion

    On August 20, 1996, the Commission responded to the Connecticut 
DEP, issuing a consistency determination and a negative determination. 
The response notes that the FEIS focuses on the concerns raised by the 
Connecticut DEP and concludes that the most important factor 
determining changes in future emissions is the relative competitive

[[Page 12458]]

position (e.g., price) of coal and natural gas. Depending on the 
relative prices of these fuels, emissions from electric generating 
facilities may increase slightly or decrease slightly. Regional 
effects, including those for the region encompassing Connecticut, are 
projected to be similar. The response also notes that these estimates 
fall within the ``noise'' level of the model. That is, they are smaller 
than the uncertainties in the science underlying the model.
    Thus, the response concludes that the Rule will not have an effect 
on the land and water uses or natural resources of Connecticut. 
Accordingly, the Commission issued a negative determination pursuant to 
the regulations implementing the CZMA, 15 CFR 930.35(d). <SUP>877
---------------------------------------------------------------------------

    \877\ In issuing a negative determination, the Commission noted 
that it questioned whether the CZMA applies to economic regulatory 
activities involving interstate electric rates and service. The 
Commission also noted that Connecticut had waived its right to 
request a consistency determination or negative determination by 
failing to notify the Commission of its request within 45 days from 
receipt of the notice of the federal activity. The Commission 
concluded that it did not waive those arguments by providing 
Connecticut with a consistency determination and negative 
determination.
---------------------------------------------------------------------------

    The response also notes that even if the Rule were to have a 
minimal effect on Connecticut's coastal zone, the Rule is consistent to 
the maximum extent practicable with the enforceable policies of the 
Connecticut Coastal Management Plan (Connecticut Plan). The Connecticut 
Coastal Management Act and supporting policies which provide the basis 
for the Connecticut Plan require that activities be consistent with the 
Clean Air Act. The Connecticut Plan provides that activities are not 
assumed to directly affect Connecticut, and thus do not require a 
consistency determination, unless they ``would result in a significant 
change in air or water quality.''
    The August 20, 1996 response concludes that the Rule is consistent 
with the requirements of the Clean Air Act and will not result in a 
significant change in air or water quality in Connecticut. In fact, 
depending on the future prices of fuel, the Rule is equally likely to 
improve air quality over Connecticut and decrease emissions deposition 
in the waters of the Long Island Sound. Thus, the Rule is consistent 
with the Connecticut Plan regardless of any slight effects it may have.
    Finally, the response notes that the action sought by Connecticut 
DEP to ensure consistency with the Connecticut Plan has already been 
taken in any event. Following issuance of the Rule, EPA, the federal 
agency charged with implementing the Clean Air Act, stated that it 
would use its authority to comprehensively address NO<INF>X emissions, 
including any potential incremental increases in emissions that might 
result from implementation of the Rule, in the 37-state region that 
makes up the Ozone Transport Assessment Group. This region includes 
Connecticut. In an Order issued May 29, 1996, the Commission agreed to 
examine the issue of mitigation of the impacts, if any, of the Rule in 
the event that EPA and the OTAG states are unsuccessful in addressing 
the NO<INF>X problem.
    Thus, the FEIS demonstrates that the Rule will not have an effect 
on any land or water use or natural resource of Connecticut's coastal 
zone. Moreover, the Rule is consistent with Connecticut's CMP. Finally, 
EPA and the Commission have taken the action sought by Connecticut DEP 
to ensure consistency with Connecticut's CMP. These actions fully 
address Connecticut DEP's coastal zone concerns.

VI. Regulatory Flexibility Act Certification

    The Regulatory Flexibility Act (RFA) <SUP>878 requires rulemakings 
to either contain a description and analysis of the effect that the 
proposed or final rule will have on small entities or to contain a 
certification that the rule will not have a significant economic impact 
on a substantial number of small entities. In the Open Access and 
Stranded Cost Final Rules, the Commission certified that the final 
rules would not impose a significant economic impact on a substantial 
number of small entities.<SUP>879
---------------------------------------------------------------------------

    \878\ 5 U.S.C. Sec. 601-612.
    \879\ Open Access Rule, 61 FR 21540 at 21691 (May 10, 1996), 
FERC Stats. & Regs. para. 31,036 at 31,898 (1996).
---------------------------------------------------------------------------

    NRECA and SBA question this certification.<SUP>880 According to 
NRECA there are about 1,000 rural electric cooperatives and 2,000 
municipal electric systems, most of which meet the RFA definition of 
small electric entity. NRECA states that the Commission has imposed 
open access, OASIS and code of conduct requirements on non-public 
utilities. NRECA maintains that if non-public utilities do not meet 
these requirements, ``they will not retain access over the long-term to 
the nation's bulk power transmission grid--access they must have if 
they wish to stay in business.'' <SUP>881
---------------------------------------------------------------------------

    \880\ The SBA filed its Request for Rehearing on June 10, 1996, 
after the statutory deadline for the filing of such a pleading. 
Accordingly, we will not accept its pleading as a request for 
rehearing but will, instead, treat it as a motion for 
reconsideration.
    On November 1, 1996, NRECA filed a supplement to its Requests 
for Rehearing and Clarifications. We will reject the supplement to 
the request for rehearing as barred by the 30 day time limit for 
filing petitions for reconsideration. Neither the Commission nor the 
courts can waive a failure to comply with the statute. See Platte 
River Whooping Crane Critical Habitat Maintenance Trust v. FERC, 876 
F.2d 109, 113 (D.C. Cir. 1989); Tennessee Gas Pipeline Company v. 
FERC, 871 F. 2d 1099, 1107 (D.C. Cir. 1989); Boston Gas Company v. 
FERC, 575 F.2d 975 (1st Cir. 1978). Accord Commonwealth Electric 
Company v. Boston Edison Company, 46 FERC para. 61,253 at 61,757, 
reh'g denied, 47 FERC para. 61,118 (1989). We will accept NRECA's 
supplemental request for clarifications.
    \881\ NRECA at 42-43.
---------------------------------------------------------------------------

    NRECA also contends that the stranded cost issue will affect small 
non-public utilities ``any time a non-public utility is required to 
render reciprocal transmission service, and loses a customer as a 
result of rendering that service, or a TDU [transmission dependent 
utility] loses a customer to an open access public utility transmission 
provider.'' <SUP>882 NRECA asserts that both the OASIS Final Rule and 
the Capacity Reservation Tariff NOPR <SUP>883 will substantially burden 
small non-public utilities.<SUP>884 NRECA further maintains that the 
Commission's waiver provisions will not alleviate the burden on small 
utilities. It states that filing a waiver request with the Commission 
is burdensome for small utilities.
---------------------------------------------------------------------------

    \882\ NRECA at 44.
    \883\ Capacity Reservation Open Access Transmission Tariffs, 
Notice of Proposed Rulemaking, IV FERC Stats. & Regs Proposed 
Regulations para. 32,519 (1996), 61 FR 21847 (May 10, 1996) 
(Capacity Reservation).
    \884\ We will discuss NRECA's arguments concerning the OASIS 
Final Rule in our order on rehearing in that proceeding. We reject 
NRECA's reference to the Capacity Tariff Reservation NOPR as 
inapposite to this proceeding. We have invited comments on the 
proposed Capacity Reservation Open Access Transmission Tariffs 
(Capacity Reservation, IV FERC Stats. & Regs. Proposed Regulations 
at 33,235, 61 FR 21847 at 21853) and will discuss those comments in 
the appropriate proceeding.
---------------------------------------------------------------------------

    SBA states that 30 percent (50 of 166) of public utilities are 
small under the SBA's definition of a small public electric 
utility.<SUP>885 SBA contends that if, as the Commission has found, 11 
percent of public utilities are small, the Final Rules will still 
affect a significant number of small public utilities.
---------------------------------------------------------------------------

    \885\ SBA Request for Reconsideration at 5. The SBA defines a 
small public electric utility as one that disposes of 4 Million MWh 
per year. 13 CFR 121.201.
---------------------------------------------------------------------------

    SBA challenges the Commission's reliance on Mid-Tex Electric 
Cooperative, Inc. v. FERC.<SUP>886 It contends that the Commission 
should have analyzed the probable effect of the Final Rules on small 
businesses by projecting, perhaps on the model of the deregulated

[[Page 12459]]

telecommunications industry, how many small electric utilities, as the 
SBA defines that term, would enter the deregulated electric utility 
market.
---------------------------------------------------------------------------

    \886\ 773 F.2d 327 (D.C. Cir. 1985) (Mid-Tex).
---------------------------------------------------------------------------

Commission Conclusion

A. Docket No. RM95-8-000 (Open Access Final Rule)

1. Public Utilities
    In the Open Access Final Rule we determined that the 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 have 
open access tariffs on file is 166. Of these, only 50 public 
utilities dispose of 4 million MWh or less per year. Eliminating 
those utilities that are affiliates of other utilities whose sales 
exceed 4 million MWh or less per year, or are not independently 
owned, the total number of public utilities affected by the Open 
Access Final Rule that qualify under the SBA's definition of small 
electric utility is 19 or 11 percent of the total number of public 
utilities that would have to have on file open access 
tariffs.<SUP>887

    \887\ FERC Stats. & Regs. at 31,897 (1996)(footnotes omitted); 
mimeo at 758-59.
---------------------------------------------------------------------------

    We do not agree with the SBA that 11 percent of all of the public 
utilities that would have to file open access tariffs with us is a 
significant number. Also, the SBA has overlooked several of the other 
findings we made as to the possible effect of the Open Access Final 
Rule on small public utilities. As we noted, of the 19 public utilities 
that would come within the SBA's definition of small electric utility, 
five have already filed open access tariffs with the Commission, so 
that the effect of the Open Access Rule on these utilities should not 
be significant.<SUP>888
---------------------------------------------------------------------------

    \888\ Id. at n.1078.
---------------------------------------------------------------------------

    Further, the Commission is specifying the non-rate terms and 
conditions of the tariffs that public utilities must file, so all 
public utilities need to do is file a rate, and the small public 
utilities with open access tariffs already on file with us need not 
even do that. They may elect to continue service under the Open Access 
Final Rule's non-rate terms and conditions at their existing rates. In 
our Final Rule we estimated that the cost for filing a rate would not, 
on average, exceed one half of one percent of total annual sales for 
small electric utilities,<SUP>889 which is not a significant economic 
impact.
---------------------------------------------------------------------------

    \889\ Id. at n.1081.
---------------------------------------------------------------------------

    We disagree with SBA that our reliance on Mid-Tex is misplaced. In 
Mid-Tex, the court accepted the Commission's conclusion that virtually 
all of the public utilities that the Commission regulates do not fall 
within the RFA's meaning of the term ``small entities.'' Mid-Tex 
involved a rule that applies to all public utilities. The Open Access 
Final Rule applies to only those public utilities that own, control or 
operate interstate transmission facilities, which are a subset of the 
group of public utilities for which Mid-Tex did not require the 
preparation of a regulatory flexibility analysis.<SUP>890
---------------------------------------------------------------------------

    \890\ Mid-Tex, 773 F. 2d at 340-43.
---------------------------------------------------------------------------

    SBA attempts to distinguish Mid-Tex by postulating that the 
Commission should have attempted to predict how many new entrants into 
a deregulated market would be small electric utilities, within the 
SBA's meaning of that term. Mid-Tex held just the opposite, deciding 
squarely that an agency need only consider the businesses that a 
regulation directly affects.<SUP>891 There is no precedent for SBA's 
suggestion that the Commission must engage in a hypothetical projection 
of how many entrants likely to enter a deregulated market may be small 
electric utilities, and we know of no satisfactory way of making such a 
projection. Entry into the telecommunications industry, which the SBA 
offers as a model, involves very different costs, distribution and 
marketing patterns and entirely different technology. There is no way, 
from looking at what has happened in the telecommunications industry, 
that the Commission could project, with any degree of accuracy, how 
many small electric utilities, if any, will enter the market following 
the effective date of the Final Open Access Rule.
---------------------------------------------------------------------------

    \891\ Id.
---------------------------------------------------------------------------

    Finally, SBA overlooks, and NRECA unreasonably discounts, the 
effect that the Commission's waiver rules have on relieving the burden 
of the Open Access Final Rule on small entities.<SUP>892 The Commission 
has recently issued a number of orders waiving the requirements of the 
Open Access Final Rule for a number of small electric 
utilities.<SUP>893 As these cases show, the Commission is carefully 
evaluating the effect of the Open Access Final Rule on small electric 
utilities and is granting waivers where appropriate, thus mitigating 
the economic effect of that rule on small entities. Indeed, as we noted 
in Order No. 888, 5 small public utilities previously had filed open 
access tariffs, and we have since, in the cases cited above, granted 
waivers to approximately 17 small public utilities.<SUP>894
---------------------------------------------------------------------------

    \892\ The Commission's waiver policy follows the SBA definition 
of small electric utility. See 5 U.S.C. Sec. 601(3) and 601(6) and 
15 U.S.C. Sec. 632(a). The RFA defines a small entity as one that is 
independently owned and not dominant in its field of operation. See 
15 U.S.C. Sec. 632(a). The SBA defines a small electric utility as 
one that disposes of 4 million MWh or less of electric energy in a 
given year. See 13 CFR 121.601 (Major Group 49-Electric, Gas and 
Sanitary Services) (1995).
    \893\ Northern States Power Company, 76 FERC para. 61,250 
(1996); Central Electric Cooperative, et al., 77 FERC para. 61,076 
(1996); Black Creek Hydro, et al., 77 FERC 61,232 (1996); Dakota 
Electric Association, et al., 78 FERC para. 61,117 (1997); Soyland 
Power Cooperative, Inc., et al., 78 FERC para. 61,095 (1997); 
Niobrara Valley Electric Membership Cooperation, Docket Nos. OA96-
146-001 and ER97-1412-000, Letter Order issued February 26, 1997.
    \894\ These total more that the 19 small public utilities we 
referenced in Order No. 888 because, since the issuance of that 
order, several entities have repaid their RUS-financed debt and 
become public utilities subject to our jurisdiction and several new 
public utilities have been created as the result of the construction 
of new facilities.
---------------------------------------------------------------------------

2. Non-Public Utilities
    We disagree with NRECA's argument that Order No. 888 imposes 
burdens upon non-public utilities. As we noted in the Final Rule, we do 
not have jurisdiction to regulate non-public utilities' rates, terms 
and conditions of transmission service under sections 205 and 206 of 
the FPA, and there is no requirement in Order No. 888 that non-public 
utilities file open access tariffs.<SUP>895
---------------------------------------------------------------------------

    \895\ See United Distribution Companies v. FERC, 88 F.3d 1105, 
1170 (July 16, 1996) (``FERC had no obligation to conduct a small 
entity impact analysis of effects on entities which it does not 
regulate.'').
---------------------------------------------------------------------------

    In addition, under the waiver provisions of the Open Access Final 
Rule, small non-public utilities may seek waiver from the reciprocity 
provision. As reflected in the cases cited above, the Commission has 
granted waivers of the reciprocity provision to 10 small non-public 
electric utilities and issued disclaimers of jurisdiction with respect 
to 19 small electric utilities, thus mitigating the effect of the Open 
Access Final Rule on small non-public electric utilities.

B. Docket No. RM94-7-000 (Stranded Cost Final Rule)

1. Public Utilities
    No rehearing requests addressed this matter.
2. Non-Public Utilities
    In Order No. 888, the Commission indicated that the Stranded Cost 
Final Rule will not impose a significant economic impact on a 
substantial number of non-public utility small entities because the 
stranded cost issue would only arise in a proceeding under sections 211 
and 212 of the FPA when, in directing transmission, the Commission 
addresses the stranded cost issue in determining a just and reasonable 
rate. NRECA counters that the stranded cost issue will ``arise: any 
time a non-public utility is required to

[[Page 12460]]

render reciprocal transmission service, and loses a customer as a 
result of rendering that service, or a TDU loses a customer to an open 
access public utility transmission provider.'' <SUP>896 NRECA submits 
that the adverse economic impact on small non-public utilities will 
``arise'' from the stranding of costs, not from the utilities' 
participation in proceedings at the Commission, and that the Commission 
``cannot in good conscience fail at least to probe the potential 
adverse economic impact on small non-public utilities of the stranded 
costs they incur as a direct result of Order No. 888.''
---------------------------------------------------------------------------

    \896\ NRECA at 44.
---------------------------------------------------------------------------

    Notwithstanding NRECA's argument that small non-public utilities 
may experience stranded costs outside of a section 211/212 proceeding, 
as we explain in Section IV.J.1, supra, our jurisdiction over the 
recovery of stranded costs by non-public utilities, and thus our 
ability to permit an opportunity for recovery of such costs, is limited 
by statute. With the exception of our section 210 interconnection and 
sections 211-212 transmission rate jurisdiction, we do not have 
jurisdiction over the rates of non-public utilities. Because the 
stranded cost issue would primarily arise as to non-public utilities 
over which the Commission has jurisdiction in a proceeding under 
sections 211 and 212 of the FPA when, in directing transmission, the 
Commission addresses the stranded cost issue in determining a just and 
reasonable rate,<SUP>897 we concluded that the Stranded Cost Final Rule 
will not impose a significant economic impact on a substantial number 
of non-public utility small entities.
---------------------------------------------------------------------------

    \897\ Stranded costs could also conceivably arise as a result of 
an ordered interconnection under section 210. However, the rates for 
such an interconnection would be established pursuant to section 212 
and could therefore also include stranded costs.
---------------------------------------------------------------------------

    Because the Commission does not have rate jurisdiction over non-
public utilities other than through sections 210, 211 and 212, the 
Commission does not have the authority to allow them to recover 
stranded costs other than through rates set under section 212. However, 
we clarify that nothing in the Final Rule was intended to preclude non-
public utilities from including stranded cost provisions in voluntary 
reciprocity tariffs or from otherwise recovering stranded costs under 
applicable law. Thus, a non-public utility that chooses voluntarily to 
offer an open access tariff for purposes of demonstrating that it meets 
the reciprocity provision can include a stranded cost provision in its 
tariff. However, adjudication of any stranded cost claims under that 
tariff is not subject to the Commission's jurisdiction.<SUP>898 If a 
non-public utility wishes to recover stranded costs pursuant to a 
tariff or otherwise, it can seek to do so subject to the review of the 
appropriate regulatory or judicial authority.
---------------------------------------------------------------------------

    \898\ Although the Commission would not determine the rate, 
including the stranded cost component of the rate, of a non-public 
utility, we would review a public utility's claim that it is 
entitled to deny service to a non-public utility because the 
stranded cost component of the non-public utility's transmission 
rate is being applied in a way that violates the principle of 
comparability.
---------------------------------------------------------------------------

VII. Information Collection Statement

    Order No. 888 contained an information collection statement for 
which the Commission obtained approval from the Office of Management 
and Budget (OMB).<SUP>899 Given that this order on rehearing makes only 
minor revisions to Order No. 888, none of which is substantive, OMB 
approval for this order will not be necessary. However, the Commission 
will send a copy of this order to OMB, for informational purposes only.
---------------------------------------------------------------------------

    \899\ One need not respond to a collection of information unless 
it displays a valid OMB control number. The OMB control number for 
this collection of information is 1902-0096.
---------------------------------------------------------------------------

    The information reporting requirements under this order are 
virtually unchanged from those contained in Order No. 888. Interested 
persons may obtain information on the reporting requirements by 
contacting the Federal Energy Regulatory Commission, 888 First Street, 
N.E., Washington, D.C. 20426 [Attention Michael Miller, Information 
Services Division, (202) 208-1415], and the Office of Management and 
Budget [Attention: Desk Officer for the Federal Energy Regulatory 
Commission (202) 395-3087].

VIII. Effective Date

    Changes to Order No. 888 made in this order on rehearing will 
become effective on May 13, 1997.

List of Subjects 18 CFR Part 35

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

    By the Commission. Commissioners Hoecker and Massey dissented in 
part with separate statements attached.
Lois D. Cashell,
Secretary.

    In consideration of the foregoing, the Commission amends part 35, 
chapter I, title 18 of the Code of Federal Regulations, as set forth 
below.

PART 35--FILING OF RATE SCHEDULES

    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. 7101-7352.

    2. Part 35 is amended by revising Sec. 35.26 to read as follows:


Sec. 35.26  Recovery of stranded costs by public utilities and 
transmitting utilities.

    (a) Purpose. This section establishes the standards that a public 
utility or transmitting utility must satisfy in order to recover 
stranded costs.
    (b) Definitions.--(1) Wholesale stranded cost means any legitimate, 
prudent and verifiable cost incurred by a public utility or a 
transmitting utility to provide service to:
    (i) A wholesale requirements customer that subsequently becomes, in 
whole or in part, an unbundled wholesale transmission services customer 
of such public utility or transmitting utility; or
    (ii) A retail customer that subsequently becomes, either directly 
or through another wholesale transmission purchaser, an unbundled 
wholesale transmission services customer of such public utility or 
transmitting utility.
    (2) Wholesale requirements customer means a customer for whom a 
public utility or transmitting utility provides by contract any portion 
of its bundled wholesale power requirements.
    (3) Wholesale transmission services means the transmission of 
electric energy sold, or to be sold, at wholesale in interstate 
commerce or ordered pursuant to section 211 of the Federal Power Act 
(FPA).
    (4) Wholesale requirements contract means a contract under which a 
public utility or transmitting utility provides any portion of a 
customer's bundled wholesale power requirements.
    (5) Retail stranded cost means any legitimate, prudent and 
verifiable cost incurred by a public utility to provide service to a 
retail customer that subsequently becomes, in whole or in part, an 
unbundled retail transmission services customer of that public utility.
    (6) Retail transmission services means the transmission of electric 
energy sold, or to be sold, in interstate commerce directly to a retail 
customer.
    (7) New wholesale requirements contract means any wholesale 
requirements contract executed after July 11, 1994, or extended or 
renegotiated to be effective after July 11, 1994.
    (8) Existing wholesale requirements contract means any wholesale

[[Page 12461]]

requirements contract executed on or before July 11, 1994.
    (c) Recovery of wholesale stranded costs.--(1) General requirement. 
A public utility or transmitting utility will be allowed to seek 
recovery of wholesale stranded costs only as follows:
    (i) No public utility or transmitting utility may seek recovery of 
wholesale stranded costs if such recovery is explicitly prohibited by a 
contract or settlement agreement, or by any power sales or transmission 
rate schedule or tariff.
    (ii) No public utility or transmitting utility may seek recovery of 
stranded costs associated with a new wholesale requirements contract if 
such contract does not contain an exit fee or other explicit stranded 
cost provision.
    (iii) If wholesale stranded costs are associated with a new 
wholesale requirements contract containing an exit fee or other 
explicit stranded cost provision, and the seller under the contract is 
a public utility, the public utility may seek recovery of such costs, 
in accordance with the contract, through rates for electric energy 
under sections 205-206 of the FPA. The public utility may not seek 
recovery of such costs through any transmission rate for FPA section 
205 or 211 transmission services.
    (iv) If wholesale stranded costs are associated with a new 
wholesale requirements contract, and the seller under the contract is a 
transmitting utility but not also a public utility, the transmitting 
utility may not seek an order from the Commission allowing recovery of 
such costs.
    (v) If wholesale stranded costs are associated with an existing 
wholesale requirements contract, if the seller under such contract is a 
public utility, and if the contract does not contain an exit fee or 
other explicit stranded cost provision, the public utility may seek 
recovery of stranded costs only as follows:
    (A) If either party to the contract seeks a stranded cost amendment 
pursuant to a section 205 or section 206 filing under the FPA made 
prior to the expiration of the contract, and the Commission accepts or 
approves an amendment permitting recovery of stranded costs, the public 
utility may seek recovery of such costs through FPA section 205-206 
rates for electric energy.
    (B) If the contract is not amended to permit recovery of stranded 
costs as described in paragraph (c)(1)(v)(A) of this section, the 
public utility may file a proposal, prior to the expiration of the 
contract, to recover stranded costs through FPA section 205-206 or 
section 211-212 rates for wholesale transmission services to the 
customer.
    (vi) If wholesale stranded costs are associated with an existing 
wholesale requirements contract, if the seller under such contract is a 
transmitting utility but not also a public utility, and if the contract 
does not contain an exit fee or other explicit stranded cost provision, 
the transmitting utility may seek recovery of stranded costs through 
FPA section 211-212 transmission rates.
    (vii) If a retail customer becomes a legitimate wholesale 
transmission customer of a public utility or transmitting utility, 
e.g., through municipalization, and costs are stranded as a result of 
the retail-turned-wholesale customer's access to wholesale 
transmission, the utility may seek recovery of such costs through FPA 
section 205-206 or section 211-212 rates for wholesale transmission 
services to that customer.
    (2) Evidentiary demonstration for wholesale stranded cost recovery. 
A public utility or transmitting utility seeking to recover wholesale 
stranded costs in accordance with paragraphs (c)(1) (v) through (vii) 
of this section must demonstrate that:
    (i) It incurred costs to provide service to a wholesale 
requirements customer or retail customer based on a reasonable 
expectation that the utility would continue to serve the customer;
    (ii) The stranded costs are not more than the customer would have 
contributed to the utility had the customer remained a wholesale 
requirements customer of the utility, or, in the case of a retail-
turned-wholesale customer, had the customer remained a retail customer 
of the utility; and
    (iii) The stranded costs are derived using the following formula: 
Stranded Cost Obligation = (Revenue Stream Estimate--Competitive Market 
Value Estimate)  x  Length of Obligation (reasonable expectation 
period).
    (3) Rebuttable presumption. If a public utility or transmitting 
utility seeks recovery of wholesale stranded costs associated with an 
existing wholesale requirements contract, as permitted in paragraph 
(c)(1) of this section, and the existing wholesale requirements 
contract contains a notice provision, there will be a rebuttable 
presumption that the utility had no reasonable expectation of 
continuing to serve the customer beyond the term of the notice 
provision.
    (4) Procedure for customer to obtain stranded cost estimate. A 
customer under an existing wholesale requirements contract with a 
public utility seller may obtain from the seller an estimate of the 
customer's stranded cost obligation if it were to leave the public 
utility's generation supply system by filing with the public utility a 
request for an estimate at any time prior to the termination date 
specified in its contract.
    (i) The public utility must provide a response within 30 days of 
receiving the request. The response must include:
    (A) An estimate of the customer's stranded cost obligation based on 
the formula in paragraph (c)(2)(iii) of this section;
    (B) Supporting detail indicating how each element in the formula 
was derived;
    (C) A detailed rationale justifying the basis for the utility's 
reasonable expectation of continuing to serve the customer beyond the 
termination date in the contract;
    (D) An estimate of the amount of released capacity and associated 
energy that would result from the customer's departure; and
    (E) The utility's proposal for any contract amendment needed to 
implement the customer's payment of stranded costs.
    (ii) If the customer disagrees with the utility's response, it must 
respond to the utility within 30 days explaining why it disagrees. If 
the parties cannot work out a mutually agreeable resolution, they may 
exercise their rights to Commission resolution under the FPA.
    (5) A customer must be given the option to market or broker a 
portion or all of the capacity and energy associated with any stranded 
costs claimed by the public utility.
    (i) To exercise the option, the customer must so notify the utility 
in writing no later than 30 days after the public utility files its 
estimate of stranded costs for the customer with the Commission.
    (A) Before marketing or brokering can begin, the utility and 
customer must execute an agreement identifying, at a minimum, the 
amount and the price of capacity and associated energy the customer is 
entitled to schedule, and the duration of the customer's marketing or 
brokering of such capacity and energy.
    (ii) If agreement over marketing or brokering cannot be reached, 
and the parties seek Commission resolution of disputed issues, upon 
issuance of a Commission order resolving the disputed issues, the 
customer may reevaluate its decision in paragraph (c)(5)(i) of this 
section to exercise the marketing or brokering option. The customer 
must notify the utility in writing within 30 days of issuance of the 
Commission's order resolving the disputed issues whether the customer 
will market or broker a portion or all of

[[Page 12462]]

the capacity and energy associated with stranded costs allowed by the 
Commission.
    (iii) If a customer undertakes the brokering option, and the 
customer's brokering efforts fail to produce a buyer within 60 days of 
the date of the brokering agreement entered into between the customer 
and the utility, the customer shall relinquish all rights to broker the 
released capacity and associated energy and will pay stranded costs as 
determined by the formula in paragraph (c)(2)(iii) of this section.
    (d) Recovery of retail stranded costs--(1) General requirement. A 
public utility may seek to recover retail stranded costs through rates 
for retail transmission services only if the state regulatory authority 
does not have authority under state law to address stranded costs at 
the time the retail wheeling is required.
    (2) Evidentiary demonstration necessary for retail stranded cost 
recovery. A public utility seeking to recover retail stranded costs in 
accordance with paragraph (d)(1) of this section must demonstrate that:
    (i) It incurred costs to provide service to a retail customer that 
obtains retail wheeling based on a reasonable expectation that the 
utility would continue to serve the customer; and
    (ii) The stranded costs are not more than the customer would have 
contributed to the utility had the customer remained a retail customer 
of the utility.

    Note: Appendices A and B and statements of Commissioners Hoecker 
and Massey will not be published in the Code of Federal Regulations.

Appendix A--List of Petitioners

Docket Nos. RM95-8-001 and RM94-7-002

----------------------------------------------------------------------------------------------------------------
              Abbreviation                                              Petitioner                              
----------------------------------------------------------------------------------------------------------------
1. AEC & SMEPA.........................  Alabama Electric Cooperative, Inc. and South Mississippi Electric Power
                                          Association.                                                          
2. AEP.................................  Operating Companies of the American Electric Power System.             
3. AL Com..............................  Alabama Public Service Commission.                                     
4. Allegheny...........................  Allegheny Power Service Corporation.                                   
5. AL Municipal........................  Alabama Municipal Electric Authority.                                  
6. American Forest & Paper.............  American Forest & Paper Association.                                   
7. AMP-Ohio............................  American Municipal Power-Ohio, Inc. and Indiana Municipal Power Agency.
8. Anaheim.............................  Cities of Anaheim, Azusa, Banning, Colton and Riverside, California.   
9. APPA................................  American Public Power Association.                                     
10. AR Com.............................  Arkansas Public Service Commission.                                    
11. Arkansas Cities....................  Arkansas Cities and Farmers Electric Cooperative.                      
12. Associated EC......................  Associated Electric Cooperative, Inc.                                  
13. Atlantic City......................  Atlantic City Electric Company.                                        
14. Basin EC...........................  Basin Electric Power Cooperative.                                      
15. Blue Ridge.........................  Blue Ridge Power Agency, Northeast Texas Electric Cooperative, Inc.,   
                                          Sam Rayburn G&T Electric Cooperative, Inc., and Tex-La Electric       
                                          Cooperative of Texas, Inc.                                            
16. BPA................................  Bonneville Power Administration.                                       
17. Cajun..............................  Ralph R. Mabey, Chapter II Trustee for Cajun Electric Power            
                                          Cooperative, Inc.                                                     
18. California DWR.....................  California Department of Water Resources.                              
19. Carolina P&L.......................  Carolina Power & Light Company.                                        
20. CCEM...............................  Coalition for a Competitive Electric Market (consisting of Coastal     
                                          Electric Services Company, Destec Power Services, Inc., Electric      
                                          Clearinghouse, Inc., Enron Power Marketing, Inc., Equitable Power     
                                          Services Company, KCS Power Marketing, Inc., MidCon Power Services    
                                          Corp. and Vitol Gas & Electric Services, Inc).                        
21. Centerior..........................  Centerior Energy Corporation.                                          
22. Central Illinois Light.............  Central Illinois Light Company.                                        
23. Central Minnesota Municipal........  Central Minnesota Municipal Power Agency.                              
24. Central Montana EC.................  Central Montana Electric Power Cooperative, Inc.                       
25. Cleveland..........................  Cleveland Public Power.                                                
26. CO Consumers Counsel...............  Colorado Office of Consumer Counsel.                                   
27. Coalition for Economic Competition.  Coalition for Economic Competition Consisting of Consolidated Edison   
                                          Company of New York, Inc., General Public Utilities Corporation,      
                                          Illinois Power Company, Long Island Lighting Company, New York State  
                                          Electric & Gas Corporation, Niagara Mohawk Power Corporation,         
                                          Northeast Utilities, and Rochester Gas and Electric Corporation.      
28. ConEd..............................  Consolidated Edison Company of New York, Inc.                          
29. Connecticut DEP....................  State of Connecticut Department of Environmental Protection.           
30. Consumers Power....................  Consumers Power Company.                                               
31. Cooperative Power..................  Cooperative Power.                                                     
32. CSW Operating Companies............  Central Power and Light, West Texas Utilities Company, Public Service  
                                          Company of Oklahoma and Southwestern Electric Power Company.          
33. CVPSC..............................  Central Vermont Public Service Corporation.                            
34. Dairyland..........................  Dairyland Power Cooperative.                                           
35. Dalton.............................  City of Dalton, Georgia.                                               
36. Detroit Edison.....................  Detroit Edison Company.                                                
37. Dispute Resolution.................  Communications and Energy Dispute Resolution Associates.               
38. Duquesne...........................  Duquesne Light Company.                                                
39. EEI................................  Edison Electric Institute.                                             
40. EGA................................  Electric Generation Association.                                       
41. El Paso............................  El Paso Electric Company.                                              
42. ELCON..............................  Electricity Consumers Resource Council, American Iron and Steel        
                                          Institute, Chemical Manufacturers Association and Council of          
                                          Industrial Boiler Owners.                                             
43. Entergy............................  Entergy Services, Inc.                                                 
44. EPRI...............................  Electric Power Research Institute.                                     
45. FL Com.............................  Florida Public Service Commission.                                     
46. Florida Power Corp.................  Florida Power Corporation.                                             
47. FMPA...............................  Florida Municipal Power Agency.                                        

[[Page 12463]]

                                                                                                                
48. FPL................................  Florida Power & Light Company.                                         
49. Freedom Energy Co..................  Freedom Energy Corporation, LLC.                                       
50. Hoosier EC.........................  Hoosier Energy Rural Electric Cooperative.                             
51. IA Com.............................  Iowa Utilities Board.                                                  
52. IL Com.............................  Illinois Commerce Commission.                                          
53. IL Industrials.....................  Illinois Industrial Energy Consumers.                                  
54. Illinois Power.....................  Illinois Power Company.                                                
55. IMPA...............................  Indiana Municipal Power Agency.                                        
56. IN Com.............................  Indiana Utility Regulatory Commission.                                 
57. IN Consumer........................  Indiana Office of Utility Consumer Counselor.                          
58. Indianapolis POL...................  Indianapolis Power & Light Company.                                    
59. IN Industrials.....................  Citizens Action Coalition of Indiana, Inc., Indiana Industrial Energy  
                                          Consumers, Inc. and Indianapolis Power & Light Company.               
60. Joint Commenters...................  Joint Commenters Supporting Clear Air and Fair Corporation.            
61. KCPL...............................  Kansas City Power & Light Company.                                     
62. LEPA...............................  Louisiana Energy and Power Authority.                                  
63. Local Furnishing Utilities.........  Local Furnishing Utilities (Long Island Lighting Company, Nevada Power 
                                          Company, San Diego Gas & Electric Company and Tuscon Electric Power   
                                          Company).                                                             
64. MA Municipals......................  Twenty Four Massachusetts Municipals.                                  
65. Maine Public Service...............  Maine Public Service Company.                                          
66. MI Com.............................  Michigan Public Service Commission and New Hampshire Public Utilities  
                                          Commission.                                                           
67. Michigan Systems...................  Michigan Public Power Agency, Michigan South Central Power Agency, and 
                                          Wolverine Power Supply Cooperative, Inc.                              
68. Minnesota P&L......................  Minnesota Power & Light Company.                                       
69. MN DPS.............................  Minnesota Department of Public Service and Minnesota Public Utilities  
                                          Commission.                                                           
70. MO/KS Coms.........................  Missouri Public Service Commission and Kansas Corporation Commission.  
71. Montana Power......................  Montana Power Company.                                                 
72. Montana-Dakota Utilities...........  Montana-Dakota Utilities Company.                                      
73. Multiple Intervenors...............  Multiple Intervenors.                                                  
74. NARUC..............................  National Association of Regulatory Utility Commissioners.              
75. NASUCA.............................  National Association of State Utility Consumer Advocates.              
76. NCMPA..............................  North Carolina Municipal Power Agency Number 1.                        
77. NE Public Power District...........  Nebraska Public Power District.                                        
78. NIMO...............................  Niagara Mohawk Power Corporation.                                      
79. NJ BPU.............................  New Jersey Board of Public Utilities.                                  
80. North Jersey.......................  North Jersey Energy Associates.                                        
81. NRECA..............................  National Rural Electric Cooperative Association.                       
82. NU.................................  Northeast Utilities Service Company.                                   
83. Nuclear Energy Institute...........  Nuclear Energy Institute.                                              
84. Nucor..............................  Nucor Corporation.                                                     
85. NWRTA..............................  Northwest Regional Transmission Association.                           
86. NY AG..............................  New York State Attorney General.                                       
87. NY Com.............................  Public Service Commission of the State of New York.                    
88. NY Municipals......................  Municipal Electric Utilities Association of New York States.           
89. NY Utilities.......................  Consolidated Edison Company of New York, Inc., Long Island Lighting    
                                          Company, New York State Electric & Gas Corporation, and Rochester Gas 
                                          and Electric Corporation.                                             
90. NYPP...............................  New York Power Pool.                                                   
91. NYSEG..............................  New York State Electric & Gas Corporation.                             
92. Occidental Chemical................  Occidental Chemical Corporation.                                       
93. Oglethorpe.........................  Oglethorpe Power Corporation.                                          
94. OH Com.............................  Public Utilities Commission of Ohio.                                   
95. OH Consumers' Counsel..............  Ohio Office of Consumers' Counsel.                                     
96. Ohio Valley........................  Ohio Valley Electric Corporation and Indiana-Kentucky Electric         
                                          Corporation.                                                          
97. Oklahoma G&E.......................  Oklahoma Gas and Electric Company Inc.                                 
98. Ontario Hydro......................  Ontario Hydro.                                                         
99. PA Com.............................  Pennsylvania Public Utility Commission.                                
100. PA Coops..........................  Pennsylvania Rural Electric Association and Allegheny Electric         
                                          Cooperative, Inc.                                                     
101. PA Munis..........................  Pennsylvania Municipal Electric Association.                           
102. PacifiCorp........................  PacifiCorp.                                                            
103. PSE&G.............................  Public Service Electric and Gas Company.                               
104. PSNM..............................  Public Service Company of New Mexico.                                  
105. Public Service Co of CO...........  Public Service Company of Colorado.                                    
106. Puget.............................  Puget Sound Power & Light Company.                                     
107. Redding...........................  City of Redding, California.                                           
108. San Francisco.....................  City and County of San Francisco.                                      
109. Santa Clara.......................  City of Santa Clara, California.                                       
110. SBA...............................  United States Small Business Administration, Office of Advocacy.       
111. SC Public Service Authority.......  South Carolina Public Service Authority.                               
112. SoCal Edison......................  Southern California Edison Company.                                    
113. Southern..........................  Southern Company Services, Inc.                                        
114. Southwestern......................  Southwestern Public Service Company.                                   
115. Speciality Steel..................  Speciality Steel Industry of North America.                            
116. Suffolk County....................  Suffolk County (New York) Electric Agency.                             
117. SWRTA.............................  Southwest Regional Transmission Association.                           

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118. Tallahassee.......................  City of Tallahassee, Florida.                                          
119. TANC..............................  Transmission Agency of Northern California.                            
120. TAPS..............................  Transmission Access Policy Study Group.                                
121. TDU Systems.......................  Transmission Dependent Utility Systems.                                
122. Texaco............................  Texaco Inc.                                                            
123. Tucson Power......................  Tucson Electric Power Company.                                         
124. Turlock...........................  Turlock Irrigation District.                                           
125. TX Com............................  Public Utility Commission of Texas.                                    
126. Umatilla EC.......................  Umatilla Electric Cooperative.                                         
127. Union Electric....................  Union Electric Company.                                                
128. Utilities For Improved transition.  Utilities For an Improved Transition (consisting of Associated Electric
                                          Cooperative, Inc., Boston Edison Company, Central Vermont Public      
                                          Service Corporation, Montaup Electric Company, Wisconsin Electric     
                                          Power Company, and Wisconsin Public Service Corporation).             
129. VA Com............................  Staff of the Virginia State Corporation Commission.                    
130. Valero............................  Valero Power Services Company.                                         
131. VEPCO.............................  Virginia Electric and Power Company.                                   
132. VT DPS............................  Vermont Department of Public Service.                                  
133. Wabash............................  Wabash Valley Power Association, Inc.                                  
134. Washington Water Power............  Washington Water Power Company.                                        
135. WI Com............................  Public Service Commission of Wisconsin.                                
136. Wisconsin Municipals..............  Municipal Electric Utilities of Wisconsin.                             
137. WY Com............................  Public Service Commission of Wyoming.                                  
----------------------------------------------------------------------------------------------------------------

Appendix B--Pro Forma Open Access Transmission Tariff

Table of Contents

I  Common Service Provisions

1  Definitions

1.1  Ancillary Services
1.2  Annual Transmission Costs
1.3  Application
1.4  Commission
1.5  Completed Application
1.6  Control Area
1.7  Curtailment
1.8  Delivering Party
1.9  Designated Agent
1.10  Direct Assignment Facilities
1.11  Eligible Customer
1.12  Facilities Study
1.13  Firm Point-To-Point Transmission Service
1.14  Good Utility Practice
1.15  Interruption
1.16  Load Ratio Share
1.17  Load Shedding
1.18  Long-Term Firm Point-To-Point Transmission Service
1.19  Native Load Customers
1.20  Network Customer
1.21  Network Integration Transmission Service
1.22  Network Load
1.23  Network Operating Agreement
1.24  Network Operating Committee
1.25  Network Resource
1.26  Network Upgrades
1.27  Non-Firm Point-To-Point Transmission Service
1.28  Open Access Same-Time Information System (OASIS)
1.29  Part I
1.30  Part II
1.31  Part III
1.32  Parties
1.33  Point(s) of Delivery
1.34  Point(s) of Receipt
1.35  Point-To-Point Transmission Service
1.36  Power Purchaser
1.37  Receiving Party
1.38  Regional Transmission Group (RTG)
1.39  Reserved Capacity
1.40  Service Agreement
1.41  Service Commencement Date
1.42  Short-Term Firm Point-To-Point Transmission Service
1.43  System Impact Study
1.44  Third-Party Sale
1.45  Transmission Customer
1.46  Transmission Provider
1.47  Transmission Provider's Monthly Transmission System Peak
1.48  Transmission Service
1.49  Transmission System

2  Initial Allocation and Renewal Procedures

2.1  Initial Allocation of Available Transmission 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

Preamble

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

[[Page 12465]]

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 Transmission 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 Transmission 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

20  Procedures if the Transmission Provider is Unable to Complete New 
Transmission Facilities for Firm Point-To-Point Transmission Service

20.1  Delays in Construction of New Facilities
20.2  Alternatives to the Original Facility Additions
20.3  Refund Obligation for Unfinished Facility Additions

21  Provisions Relating to Transmission Construction and Services on 
the Systems of Other Utilities

21.1  Responsibility for Third-Party System Additions
21.2  Coordination of Third-Party System Additions

22  Changes in Service Specifications

22.1  Modifications On a Non-Firm Basis
22.2  Modification On a Firm Basis
23  Sale or Assignment of Transmission Service
23.1  Procedures for Assignment or Transfer of Service
23.2  Limitations on Assignment or Transfer of Service
23.3  Information on Assignment or Transfer of Service

24  Metering and Power Factor Correction at Receipt and Delivery 
Points(s)

24.1  Transmission Customer Obligations
24.2  Transmission Provider Access to Metering Data
24.3  Power Factor

25  Compensation for Transmission Service

26  Stranded Cost Recovery

27  Compensation for New Facilities and Redispatch Costs

III. Network Integration Transmission Service

Preamble

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

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 Transmission 
Service
Schedule 8
    Non-Firm Point-To-Point Transmission 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 Transmission 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

[[Page 12466]]

    Network Operating Agreement
    Attachment H
    Annual Transmission Revenue Requirement For Network Integration 
Transmission Service
    Attachment I
    Index Of Network Integration Transmission Service Customers

I. Common Service Provisions

1  Definitions

    1.1  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.
    1.2  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 until amended by 
the Transmission Provider or modified by the Commission.
    1.3  Application: A request by an Eligible Customer for 
transmission service pursuant to the provisions of the Tariff.
    1.4  Commission: The Federal Energy Regulatory Commission.
    1.5  Completed Application: An Application that satisfies all of 
the information and other requirements of the Tariff, including any 
required deposit.
    1.6  Control Area: An electric power system or combination of 
electric power systems to which a common automatic generation 
control scheme is applied in order to:
    (1) Match, at all times, the power output of the generators 
within the electric power system(s) and capacity and energy 
purchased from entities outside the electric power system(s), with 
the load within the electric power system(s);
    (2) Maintain scheduled interchange with other Control Areas, 
within the limits of Good Utility Practice;
    (3) Maintain the frequency of the electric power system(s) 
within reasonable limits in accordance with Good Utility Practice; 
and
    (4) Provide sufficient generating capacity to maintain operating 
reserves in accordance with Good Utility Practice.
    1.7  Curtailment: A reduction in firm or non-firm transmission 
service in response to a transmission capacity shortage as a result 
of system reliability conditions.
    1.8  Delivering Party: The entity supplying capacity and energy 
to be transmitted at Point(s) of Receipt.
    1.9  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.
    1.10  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.
    1.11  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.
    1.12  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.
    1.13  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.
    1.14  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.
    1.15  Interruption: A reduction in non-firm transmission service 
due to economic reasons pursuant to Section 14.7.
    1.16  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.
    1.17  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.
    1.18  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.
    1.19  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.
    1.20  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.
    1.21  Network Integration Transmission Service: The transmission 
service provided under Part III of the Tariff.
    1.22  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.
    1.23  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.
    1.24  Network Operating Committee: A group made up of 
representatives from the Network Customer(s) and the Transmission 
Provider established to coordinate operating criteria and other 
technical considerations required for implementation of Network 
Integration Transmission Service under Part III of this Tariff.
    1.25  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.
    1.26  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.
    1.27  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.

[[Page 12467]]

    1.28  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.
    1.29  Part I: Tariff Definitions and Common Service Provisions 
contained in Sections 2 through 12.
    1.30  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.
    1.31  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.
    1.32  Parties: The Transmission Provider and the Transmission 
Customer receiving service under the Tariff.
    1.33  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.
    1.34  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.
    1.35  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.
    1.36  Power Purchaser: The entity that is purchasing the 
capacity and energy to be transmitted under the Tariff.
    1.37  Receiving Party: The entity receiving the capacity and 
energy transmitted by the Transmission Provider to Point(s) of 
Delivery.
    1.38  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.
    1.39  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.
    1.40  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.
    1.41  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.
    1.42  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.
    1.43  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.
    1.44  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.
    1.45  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.
    1.46  Transmission Provider: The public utility (or its 
Designated Agent) that owns, controls, or operates facilities used 
for the transmission of electric energy in interstate commerce and 
provides transmission service under the Tariff.
    1.47  Transmission Provider's Monthly Transmission System Peak: 
The maximum firm usage of the Transmission Provider's Transmission 
System in a calendar month.
    1.48  Transmission Service: Point-To-Point Transmission Service 
provided under Part II of the Tariff on a firm and non-firm basis.
    1.49  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 Transmission 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 one-year 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 a competing request by any new Eligible Customer 
and to pay the current just and reasonable rate, as approved by the 
Commission, for such service. 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 one-year or 
longer.

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

[[Page 12468]]

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.
    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 Sec. 37 of 
the Commission's regulations (Open Access Same-Time Information 
System and Standards of Conduct for Public Utilities). In the event 
available transmission 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 C.F.R. Sec. 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 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

[[Page 12469]]

(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

    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. In addition, 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.

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.
    12.4  Costs: Each Party shall be responsible for its own costs 
incurred during the arbitration process and for the following costs, 
if applicable:
    (A) 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
    (B) 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 transmission of such capacity and energy to 
designated Point(s) of Delivery.

13  Nature of Firm Point-To-Point Transmission Service

    13.1  Term: The minimum term of Firm Point-To-Point Transmission 
Service shall be one day and the maximum term shall be specified in 
the Service Agreement.
    13.2  Reservation Priority: 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 reserved service. Reservations for Short-
Term Firm Point-To-Point Transmission Service will be conditional 
based upon the length of the requested transaction. If the 
Transmission System becomes oversubscribed, requests for longer term 
service may preempt requests for shorter term service up to the 
following

[[Page 12470]]

deadlines: one day before the commencement of daily service, one 
week before the commencement of weekly service, and one month before 
the commencement of monthly service. Before the conditional 
reservation deadline, if available transmission 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. 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 [insert date 
sixty (60) days after publication in Federal Register] 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 system, Curtailments will be made on a non-
discriminatory basis to the transaction(s) that effectively relieve 
the constraint. 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 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 
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.
    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 10:00 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 10:00 a.m. will be accommodated, 
if practicable. Hour-to-hour schedules of any capacity and energy 
that is to be delivered must be stated in increments of 1,000 kW per 
hour [or a reasonable increment that is generally accepted in the 
region and is consistently adhered to by the Transmission Provider]. 
Transmission Customers within the Transmission Provider's service 
area with multiple requests for Transmission Service at a Point of 
Receipt, each of which is under 1,000 kW per hour, may consolidate 
their service requests at a common point of receipt into units of 
1,000 kW per hour for scheduling and billing purposes. Scheduling 
changes will be

[[Page 12471]]

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 transmission 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 to reservations with a longer duration of 
service. In the event the Transmission System is constrained, 
competing requests of 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 [insert 
date sixty (60) days after publication in Federal Register] 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 2:00 
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 
2:00 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. 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 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

[[Page 12472]]

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 Transmission Capability: A 
description of the Transmission Provider's specific methodology for 
assessing available transmission capability posted on the 
Transmission Provider's OASIS (Section ) is contained in Attachment 
of the Tariff. In the event sufficient transmission 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 expand or modify its 
Transmission System to provide the requested Firm Transmission 
Service, 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 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.
    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; and
    e. The Transmission Customer has executed a Point-To-Point 
Service Agreement or has agreed to receive service pursuant to 
Section 15.3.
    16.2  Transmission Customer Responsibility for Third-Party 
Arrangements: Any scheduling arrangements that may be required by 
other electric systems shall be the responsibility of the 
Transmission Customer requesting service. The Transmission Customer 
shall provide, unless waived by the Transmission Provider, 
notification to the Transmission Provider identifying such systems 
and authorizing them to schedule the capacity and energy to be 
transmitted by the Transmission Provider pursuant to Part II of the 
Tariff on behalf of the Receiving Party at the Point of Delivery or 
the Delivering Party at the Point of Receipt. However, the 
Transmission Provider will undertake reasonable efforts to assist 
the Transmission Customer in making such arrangements, including 
without limitation, providing any information or data required by 
such other electric system pursuant to Good Utility Practice.

17  Procedures for Arranging Firm Point-To-Point Transmission 
Service

    17.1  Application: A request for Firm Point-To-Point 
Transmission Service for periods of one year or longer must contain 
a written Application to: [Transmission Provider Name and Address], 
at least sixty (60) days in advance of the calendar month in which 
service is to commence. The Transmission Provider will consider 
requests for such firm service on shorter notice when feasible. 
Requests for firm service for periods of less than one year shall be 
subject to expedited procedures that shall be negotiated between the 
Parties within the time constraints provided in Section 17.5. All 
Firm Point-To-Point Transmission Service requests should be 
submitted by entering the information listed below on the 
Transmission Provider's OASIS. Prior to implementation of the 
Transmission Provider's OASIS, a Completed Application may be 
submitted by (i) transmitting the required information to the 
Transmission Provider by telefax, or (ii) providing the information 
by telephone over the Transmission Provider's time recorded 
telephone line. Each of these methods will provide a time-stamped 
record for establishing the priority of the Application.
    17.2  Completed Application: A Completed Application shall 
provide all of the information included in 18 CFR Sec. 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; and
    (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.

[[Page 12473]]

    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 
Sec. 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 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 , 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 Sec. 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.
    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 Transmission Capability: 
Following receipt of a tendered schedule the Transmission Provider 
will make a determination on a non-discriminatory basis of available 
transmission capability pursuant to Section

[[Page 12474]]

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

      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, 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, 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 transmission capability to 
satisfy the full amount of a Completed Application for Firm Point-
To-Point Transmission Service, the Transmission Provider nonetheless 
shall be obligated to offer and provide the portion of the requested 
Firm Point-To-Point Transmission Service that can be accommodated 
without addition of any facilities and through redispatch. However, 
the Transmission Provider shall not be obligated to provide the 
incremental amount of requested Firm Point-To-Point Transmission 
Service that requires the addition of facilities or upgrades to the 
Transmission System until such facilities or upgrades have been 
placed in service.
    19.8  Expedited Procedures for New Facilities: In lieu of the 
procedures set forth above, the Eligible Customer shall have the 
option to expedite the process by requesting the Transmission 
Provider to tender at one time, together with the results of 
required studies, an ``Expedited Service Agreement'' pursuant to 
which the Eligible Customer would agree to compensate the 
Transmission Provider for all costs incurred pursuant to the terms 
of the Tariff. In order to exercise this option, the Eligible 
Customer shall request in

[[Page 12475]]

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.

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 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 or it may refer the dispute to the Commission 
for resolution.
    20.3  Refund Obligation for Unfinished Facility Additions: If 
the Transmission Provider and the Transmission Customer mutually 
agree that no other reasonable alternatives exist and the requested 
service cannot be provided out of existing capability under the 
conditions of Part II of the Tariff, the obligation to provide the 
requested Firm Point-To-Point Transmission Service shall terminate 
and any deposit made by the Transmission Customer shall be returned 
with interest pursuant to Commission regulations 35.19a(a)(2)(iii). 
However, the Transmission Customer shall be responsible for all 
prudently incurred costs by the Transmission Provider through the 
time construction was suspended.

21  Provisions Relating to Transmission Construction and Services 
on the Systems of Other Utilities

    21.1  Responsibility for Third-Party System Additions: The 
Transmission Provider shall not be responsible for making 
arrangements for any necessary engineering, permitting, and 
construction of transmission or distribution facilities on the 
system(s) of any other entity or for obtaining any regulatory 
approval for such facilities. The Transmission Provider will 
undertake reasonable efforts to assist the Transmission Customer in 
obtaining such arrangements, including without limitation, providing 
any information or data required by such other electric system 
pursuant to Good Utility Practice.
    21.2  Coordination of Third-Party System Additions: In 
circumstances where the need for transmission facilities or upgrades 
is identified pursuant to the provisions of Part II of the Tariff, 
and if such upgrades further require the addition of transmission 
facilities on other systems, the Transmission Provider shall have 
the right to coordinate construction on its own system with the 
construction required by others. The Transmission Provider, after 
consultation with the Transmission Customer and representatives of 
such other systems, may defer construction of its new transmission 
facilities, if the new transmission facilities on another system 
cannot be completed in a timely manner. The Transmission Provider 
shall notify the Transmission Customer in writing of the basis for 
any decision to defer construction and the specific problems which 
must be resolved before it will initiate or resume construction of 
new facilities. Within sixty (60) days of receiving written 
notification by the Transmission Provider of its intent to defer 
construction pursuant to this section, the Transmission Customer may 
challenge the decision in accordance with the dispute resolution 
procedures pursuant to Section 12 or it may refer the dispute to the 
Commission for resolution.

22  Changes in Service Specifications

    22.1  Modifications On a Non-Firm Basis: The Transmission 
Customer taking Firm Point-To-Point Transmission Service may request 
the Transmission Provider to provide transmission service on a non-
firm basis over Receipt and Delivery Points other than those 
specified in the Service Agreement (``Secondary Receipt and Delivery 
Points''), in amounts not to exceed its firm capacity reservation, 
without incurring an additional Non-Firm Point-To-Point Transmission 
Service charge or executing a new Service Agreement, subject to the 
following conditions.
    (a) Service provided over Secondary Receipt and Delivery Points 
will be non-firm only, on an as-available basis and 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 the Reseller 
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. 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

[[Page 12476]]

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.
    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 
Point(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 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 transmission capability. The 
Transmission Provider shall include the Network Customer's Network 
Load in its Transmission System planning and shall, consistent with 
Good Utility Practice, endeavor to construct and place into service 
sufficient transmission capacity to deliver the Network Customer's 
Network Resources to serve its Network Load on a basis comparable to 
the Transmission Provider's delivery of its own generating and 
purchased resources to its Native Load Customers.
    28.3  Network Integration Transmission Service: The Transmission 
Provider will provide firm transmission service over its 
Transmission System to the Network Customer for the delivery of 
capacity and energy from its designated Network Resources to service 
its Network Loads on a basis that is comparable to the Transmission 
Provider's use of the Transmission System to reliably serve its 
Native Load Customers.
    28.4  Secondary Service: The Network Customer may use the 
Transmission Provider's Transmission System to deliver energy to its 
Network Loads from resources that have not been designated as 
Network Resources. Such energy shall be transmitted, on an as-
available basis, at no additional charge. Deliveries from resources 
other than Network Resources will have a higher priority than any 
Non-Firm Point-To-Point Transmission Service under Part II of the 
Tariff.
    28.5  Real Power Losses: Real Power Losses are associated with 
all transmission service. The Transmission Provider is not obligated 
to provide Real Power Losses. The Network Customer is responsible 
for replacing losses associated with all transmission service as 
calculated by the Transmission Provider. The applicable Real Power 
Loss factors are as follows: [To be completed by the Transmission 
Provider].
    28.6  Restrictions on Use of Service: The Network Customer shall 
not use Network Integration Transmission Service for (i) sales of 
capacity and energy to non-designated loads, or (ii) direct or 
indirect provision of transmission service by the Network Customer 
to third parties. All Network Customers taking Network Integration 
Transmission Service shall use Point-To-Point Transmission Service 
under Part II of the Tariff for any Third-Party Sale which requires 
use of the Transmission Provider's Transmission System.

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

[[Page 12477]]

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.
    29.2  Application Procedures: An Eligible Customer requesting 
service under Part III of the Tariff must submit an Application, 
with a deposit approximating the charge for one month of service, to 
the Transmission Provider as far as possible in advance of the month 
in which service is to commence. Unless subject to the procedures in 
Section 2, Completed Applications for Network Integration 
Transmission Service will be assigned a priority according to the 
date and time the Application is received, with the earliest 
Application receiving the highest priority. Applications should be 
submitted by entering the information listed below on the 
Transmission Provider's OASIS. Prior to implementation of the 
Transmission Provider's OASIS, a Completed Application may be 
submitted by (i) transmitting the required information to the 
Transmission Provider by telefax, or (ii) providing the information 
by telephone over the Transmission Provider's time recorded 
telephone line. Each of these methods will provide a time-stamped 
record for establishing the service priority of the Application. A 
Completed Application shall provide all of the information included 
in 18 CFR Sec. 2.20 including but not limited to the following:
    (i) The identity, address, telephone number and facsimile number 
of the party requesting service;
    (ii) A statement that the party requesting service is, or will 
be upon commencement of service, an Eligible Customer under the 
Tariff;
    (iii) A description of the Network Load at each delivery point. 
This description should separately identify and provide the Eligible 
Customer's best estimate of the total loads to be served at each 
transmission voltage level, and the loads to be served from each 
Transmission Provider substation at the same transmission voltage 
level. The description should include a ten (10) year forecast of 
summer and winter load and resource requirements beginning with the 
first year after the service is scheduled to commence;
    (iv) The amount and location of any interruptible loads included 
in the Network Load. This shall include the summer and winter 
capacity requirements for each interruptible load (had such load not 
been interruptible), that portion of the load subject to 
interruption, the conditions under which an interruption can be 
implemented and any limitations on the amount and frequency of 
interruptions. An Eligible Customer should identify the amount of 
interruptible customer load (if any) included in the 10 year load 
forecast provided in response to (iii) above;
    (v) A description of Network Resources (current and 10-year 
projection), 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; and

    (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.
    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

[[Page 12478]]

be made by a request for modification of service pursuant to an 
Application under Section 29.
    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 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.
    30.5  Network Customer Redispatch Obligation: As a condition to 
receiving Network Integration Transmission Service, the Network 
Customer agrees to redispatch its Network Resources as requested by 
the Transmission Provider pursuant to Section 33.2. To the extent 
practical, the redispatch of resources pursuant to this section 
shall be on a least cost, non-discriminatory basis between all 
Network Customers, and the Transmission Provider.
    30.6  Transmission Arrangements for Network Resources Not 
Physically Interconnected With The Transmission Provider: The 
Network Customer shall be responsible for any arrangements necessary 
to deliver capacity and energy from a Network Resource not 
physically interconnected with the Transmission Provider's 
Transmission System. The Transmission Provider will undertake 
reasonable efforts to assist the Network Customer in obtaining such 
arrangements, including without limitation, providing any 
information or data required by such other entity pursuant to Good 
Utility Practice.
    30.7  Limitation on Designation of Network Resources: The 
Network Customer must demonstrate that it owns or has committed to 
purchase generation pursuant to an executed contract in order to 
designate a generating resource as a Network Resource. 
Alternatively, the Network Customer may establish that execution of 
a contract is contingent upon the availability of transmission 
service under Part III of the Tariff.
    30.8  Use of Interface Capacity by the Network Customer: There 
is no limitation upon a Network Customer's use of the Transmission 
Provider's Transmission System at any particular interface to 
integrate the Network Customer's Network Resources (or substitute 
economy purchases) with its Network Loads. However, a Network 
Customer's use of the Transmission Provider's total interface 
capacity with other transmission systems may not exceed the Network 
Customer's Load.
    30.9  Network Customer Owned Transmission Facilities: The 
Network Customer that owns existing transmission facilities that are 
integrated with the Transmission Provider's Transmission System may 
be eligible to receive consideration either through a billing credit 
or some other mechanism. In order to receive such consideration the 
Network Customer must demonstrate that its transmission facilities 
are integrated into the plans or operations of the Transmission 
Provider to serve its power and transmission customers. For 
facilities constructed by the Network Customer subsequent to the 
Service Commencement Date under Part III of the Tariff, the Network 
Customer shall receive credit where such facilities are jointly 
planned and installed in coordination with the Transmission 
Provider. Calculation of the credit 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 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 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. The Network Customer also 
shall provide the Transmission Provider with timely written notice 
of material changes in any other information provided in its 
Application relating to the Network Customer's Network Load, Network 
Resources, its transmission system or other aspects of its 
facilities or operations affecting the Transmission Provider's 
ability to provide reliable service.

32  Additional Study Procedures For Network Integration 
Transmission Service Requests

    32.1  Notice of Need for System Impact Study: After receiving a 
request for service, the Transmission Provider shall determine on a 
non-discriminatory basis whether a System Impact Study is needed. A 
description of the Transmission Provider's methodology for 
completing a System Impact Study is provided in Attachment . 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

[[Page 12479]]

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, 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.

33  Load Shedding and Curtailments

    33.1  Procedures: Prior to the Service Commencement Date, the 
Transmission Provider and the Network Customer shall establish Load 
Shedding and Curtailment procedures pursuant to the Network 
Operating Agreement with the objective of responding to 
contingencies on the Transmission System. 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.
    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

[[Page 12480]]

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.
    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

[[Page 12481]]

follow the moment-by-moment changes in load. The obligation to 
maintain this balance between resources and load lies with the 
Transmission Provider (or the Control Area operator that performs 
this function for the Transmission Provider). The Transmission 
Provider must offer this service when the transmission service is 
used to serve load within its Control Area. The Transmission 
Customer must either purchase this service from the Transmission 
Provider or make alternative comparable arrangements to satisfy its 
Regulation and Frequency Response Service obligation. The amount of 
and charges for Regulation and Frequency Response Service are set 
forth below. To the extent the Control Area operator performs this 
service for the Transmission Provider, charges to the Transmission 
Customer are to reflect only a pass-through of the costs charged to 
the Transmission Provider by that Control Area operator.

Schedule 4--Energy Imbalance Service

    Energy Imbalance Service is provided when a difference occurs 
between the scheduled and the actual delivery of energy to a load 
located within a Control Area over a single hour. The Transmission 
Provider must offer this service when the transmission service is 
used to serve load within its Control Area. The Transmission 
Customer must either purchase this service from the Transmission 
Provider or make alternative comparable arrangements 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 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) 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.
    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.

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

[[Page 12482]]

have a Completed Application for Firm Point-To-Point Transmission 
Service under the Tariff.
    3.0  The Transmission Customer has provided to the Transmission 
Provider an Application deposit in accordance with the provisions of 
Section 17.3 of the Tariff.
    4.0  Service under this agreement shall commence on the later of 
(1) the requested service commencement date, or (2) the date on 
which construction of any Direct Assignment Facilities and/or 
Network Upgrades are completed, or (3) such other date as it is 
permitted to become effective by the Commission. Service under this 
agreement shall terminate on such date as mutually agreed upon by 
the parties.
    5.0   The Transmission Provider agrees to provide and the 
Transmission Customer agrees to take and pay for Firm Point-To-Point 
Transmission Service in accordance with the provisions of Part II of 
the Tariff and this Service Agreement.
    6.0  Any notice or request made to or by either Party regarding 
this Service Agreement shall be made to the representative of the 
other Party as indicated below.

Transmission Provider

----------------------------------------------------------------------

----------------------------------------------------------------------

----------------------------------------------------------------------

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):

----------------------------------------------------------------------

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

    8.3  Direct Assignment Facilities Charge:

----------------------------------------------------------------------

----------------------------------------------------------------------

    8.4  Ancillary Services Charges:

----------------------------------------------------------------------

----------------------------------------------------------------------

----------------------------------------------------------------------

----------------------------------------------------------------------

----------------------------------------------------------------------

----------------------------------------------------------------------

----------------------------------------------------------------------

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 Transmission Capability

    To be filed by the Transmission Provider.

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.

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.

[[Page 12483]]

Attachment I--Index of Network Integration Transmission Service 
Customers

----------------------------------------------------------------------
Customer

    Date of Service Agreement
----------------------------------------------------------------------
    Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities. Docket No. 
RM95-8-001.
    Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities. Docket No. RM94-7-002.

(Issued March 4, 1997)

HOECKER, Commissioner, dissenting in part:

I. General Observations

    Today's rehearing order makes Order No. 888 ripe for judicial 
review and largely concludes the most ambitious generic rulemaking 
effort in this agency's history. The scores of specific policy calls 
embodied in Order No. 888-A represent reasoned decisionmaking that, 
in its sheer level of detail, takes us to the outer limits of our 
ability to predict or control the proper future operation of the 
market. Still, the timeliness of this order ought to be welcomed. 
Having satisfactorily demonstrated that the fundamental rules 
governing a network as complex and important as the Nation's 
transmission grid can be changed and made to work, the Commission 
will henceforth be engaged in implementing open access tariffs and 
dealing with the direct and indirect consequences of bulk power 
competition. The mantle of major policymaking now shifts to the 
states and to the U.S. Congress.
    During this proceeding, the industry has continued to evolve. In 
ten short months, merger and acquisition activity has increased 
dramatically and may foretell a more significant reconfiguration in 
the future. The concept of an independent system operator has 
attained significant credibility as a possible way to throttle 
market power, ensure system reliability, and rationalize the bulk 
power market. Retail access and customer choice suddenly dominate 
the restructuring debate, although the future competitive retail 
power market still defies prediction. The demarcation between state 
and federal jurisdiction is actively being tested. And, as the 
implications of full stranded cost recovery are being thought 
through within the industry, companies are also trying to diagnose 
and address their other competitive vulnerabilities. These 
remarkable and largely unforeseeable changes counsel against the 
temptation among public policymakers to over-plan and over-prescribe 
the future of power markets.

II. Partial Dissent

    In Order No. 888, the Commission announced that it would be the 
``primary forum'' for stranded cost claims in those instances where 
a retail power customer turns wholesale wheeling customer, usually 
through a municipalization. I dissented from that portion of the 
Final Rule because I concluded that the Commission's decision to 
take responsibility for stranded costs arising from municipalization 
was insupportable as a matter of either policy or law. As the 
``primary forum'' for recovery of these costs, the Commission will 
be required to second-guess certain state retail stranded cost 
determinations, even when state regulators and state statutes 
address the issue sufficiently. This would, in my estimation, 
encourage forum shopping and fundamentally contradict our approach 
in the retail wheeling situation, where retail stranded costs are 
subject to Commission action only if the state regulatory body lacks 
authority to deal with this important transitional issue. I continue 
to hold these views.
    The majority has bolstered its position today with additional 
arguments connecting the Commission's actions in Order No. 888 to 
the wholesale status of new municipal power customers. While 
inventive, the majority rests its theory of jurisdiction on a 
tenuous theory of cause and effect. Briefly, the rehearing order 
distinguishes wholesale stranded costs from retail stranded costs 
not by the nature of the costs, but by the status of the customer 
(i.e., a wholesale transmission services customer versus a retail 
transmission services customer) with whom the costs are associated. 
It further contends that jurisdiction over stranded costs depends on 
``whether the transmission tariffs used by the customer to escape 
its former power supplier * * * were required by this Commission or 
by a state commission''. The majority states that this Commission 
will serve as the ``primary forum'' for stranded cost recovery only 
where there exists a direct nexus between the availability and use 
of FERC's open access transmission tariffs and the stranding of 
costs.
    I am not persuaded by the rationale supplied by my colleagues. I 
continue to believe that municipalization, like retail wheeling, 
would be unavailable to retail customers as a competitive supply 
alternative but for state action. In both instances, it is state law 
that provides the legal means for retail customers to gain access to 
FERC-jurisdictional transmission tariffs. In the final analysis, I 
am not persuaded that the public interest is served by the 
majority's intrusion into an area potentially policed under state 
law, notwithstanding the Commission's strong commitment to full cost 
recovery.
    In today's order, the Commission also broadens its ``primary 
forum'' approach to include situations involving the expansion of 
existing municipal utility systems, for example through annexation 
of retail customer load or additional service territory. I contend, 
however, that the ``primary forum'' approach is no more appropriate 
for municipal annexations than it is for new municipalizations.
    The discussion of this issue in Order No. 888-A heightens my 
previous concerns in a number of ways. First, the majority's 
position is based on the alleged similarities between the creation 
of a new municipal utility system and the expansion of an existing 
municipal utility system. In both cases, they argue, a nexus exists 
between the municipalization and Commission-required transmission 
access; the salient connection is the use that the new wholesale 
customer makes of the former supplying utility's transmission 
system. If one were to assume the correctness of the majority's 
municipalization approach, it would make sense to limit its stranded 
cost recovery provisions to such circumstances only. But, there are 
two more compelling factors that determine the legitimacy of any 
stranded cost approach. First, like retail wheeling, all 
municipalizations, whether new or annexations, occur pursuant to 
state law. As already discussed, state action allows retail 
customers to aggregate load and, through municipalization, gain 
access to FERC-jurisdictional transmission tariffs. Second, the risk 
of annexation (and with it the loss of retail load) existed long 
before enactment of the Energy Policy Act or implementation of Order 
No. 888. I believe these factors argue for treatment of all costs 
incurred to serve retail load and stranded pursuant to state 
action--whether by retail wheeling, new municipalization, or 
annexation--by the same state regulatory body. I do not dispute, 
however, that the Commission should step in when states fail to 
ensure some level of stranded cost recovery, thereby creating a 
regulatory gap.
    The rehearing order has an additional problem. It states that 
the Commission will not necessarily be the ``primary forum'' for 
stranded cost recovery in all cases of municipal annexation. The 
majority's new willingness to decide stranded costs arising from the 
annexation of new load will therefore require a finding that the 
existing municipality will use the transmission system of the 
annexed retail customers' former supplier to provide service to the 
annexed load. This approach is necessitated by the ``nexus'' theory 
of jurisdiction over the underlying stranded costs, and it 
represents a novel theory of law. Moreover, the administrative 
difficulties associated with this particular fact-finding will be 
extensive. An existing municipality already has transmission and 
generation service arrangements in place. With access to additional 
generation resources now available in the newly competitive 
wholesale power market, a municipality ultimately may be served by a 
number of suppliers, possibly in addition to its own resources. In 
such circumstances, the difficulty in determining which generation 
resources, and hence which transmission services, are being used to 
supply service to the annexed customers in particular may be 
virtually insurmountable. Under the nexus test, the Commission must 
settle that matter preliminarily just to decide whether it is the 
proper forum for addressing the costs stranded by an annexation.
    To compound this practical problem, the majority's commitment to 
give ``great weight to a state's view'' of what stranded costs are 
recoverable under state law in these circumstances, and to deduct 
the amount of state stranded cost awards from the amount that a 
utility may seek to recover from this Commission, is likely to prove 
a hollow promise. Such deference would require a prior stranded cost 
determination on the merits by state regulators, despite the 
majority's instruction to the parties to raise all stranded cost 
claims under the municipalization scenario before this Commission 
``in the first instance.''

[[Page 12484]]

Deference in this context is a slippery proposition for other 
reasons, too. Naturally, states may perceive equity considerations, 
cost causation principles, <SUP>1 and market risk factors<SUP>2 
differently than the Commission, and consequently they may not share 
the Commission's view that utilities are entitled to full recovery 
of stranded costs here. Because of this potential difference of 
opinion, I suspect that the amount of deference that the Commission 
provides to the states may be directly proportional to the level of 
stranded cost recovery that states grant the utilities.
---------------------------------------------------------------------------

    \1\ Pipeline Service Obligations and Revisions to Regulations 
Governing Self-Implementing Transportation Under Part 284 of the 
Commission's Regulations and Regulation of Natural Gas Pipelines 
After Partial Wellhead Decontrol, Order No. 636-C, 78 FERC para. 
61,186 (1997).
    \2\ Mechanisms for Passthrough of Pipeline Take-or-Pay Buyout 
and Buydown Costs, Order No. 528-A, 54 FERC para. 61,095 (1991).
---------------------------------------------------------------------------

    In sum, the majority's ingenious attempt to federalize stranded 
cost claims arising from municipalization, while admirable in terms 
of the need to resolve transition cost issues expeditiously, is more 
likely to cause greater uncertainty and more argument about the 
appropriate standard to apply than it is to promote settlement of 
the matter.
    I therefore respectfully dissent in small part to Order No. 888-
A.
James J. Hoecker,
Commissioner.
    Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities. Docket No. 
RM95-8-001.
    Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities. Docket No. RM94-7-002.

Order No. 888-A

(Issued March 4, 1997)

MASSEY, Commissioner, dissenting in part:

    I dissent in part, from this otherwise excellent rule, on a 
single issue. I continue to believe, as I stated in my dissent to 
Order No. 888, that the Commission should treat stranded costs 
arising from retail competition and municipalizations similarly.
    Municipalization occurs under state rather than federal law. The 
majority's decision in Order No. 888 that FERC should be the primary 
forum for addressing the recovery of stranded costs caused by 
municipalization boldly and unnecessarily preempts legitimate state 
authority. Today's order perpetuates and compounds this error by 
extending federal preemption to stranded costs arising from 
municipal annexations as well.
    Many state commissions have express legislative authority to 
address these issues and should not be prohibited from doing so by 
federal regulators. It is only when a state commission does not have 
the authority, or has the authority and fails to use it, that the 
Commission should be available as a stranded cost recovery forum of 
last resort.
    On this one issue, I respectfully dissent.
William L. Massey,
Commissioner.
[FR Doc. 97-5767 Filed 3-13-97; 8:45 am]
BILLING CODE 6717-01-P


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