[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]]
_______________________________________________________________________
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.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, 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.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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
hillier__t@a1.eop.gov. 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 1935.4 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.
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\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.5
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\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.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.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.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) 9 that the generation
dominance standard for market-based sales from new capacity should be
dropped.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.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.'' 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.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.
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\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.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.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.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.
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\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.
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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.
RM96-6-000.17 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.18
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\17\ FERC Stats. & Regs. para. 35,531 (1996).
\18\ FERC Stats. & Regs. at 31,661; mimeo at 77-78.
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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.19
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\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).
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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.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.
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The Commission found that it would be against the public interest
to permit a Mobile-Sierra clause in an existing wholesale requirements
contract 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.
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\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 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 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.24
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\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.
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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.25 Utilities For Improved
Transition asserts that the Commission cannot rely on economic theory
as a substitute for substantial evidence.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.
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\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.'' 27
---------------------------------------------------------------------------
\27\ PSE&G at 6.
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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.28
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\28\ See also PSE&G.
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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.29
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\29\ See also Carolina P&L.
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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. [30]
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\30\ Blue Ridge at 16.
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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. 31 Additionally, it applies to any contract revisions
sought, whether or not they relate to stranded costs. 32
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\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.
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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.33
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\33\ Similarly, as discussed in Section IV.J, parties have taken
extreme positions as to stranded cost recovery.
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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.34
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\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).
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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.35
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\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.
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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.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.
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\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, 1994,37 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.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.39 While monopolist transmission providers
may not have exercised monopoly power in all situations,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.41
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\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. 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.
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\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.
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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 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.44
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\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).
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\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.
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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\
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\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.).
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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\
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\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.
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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.
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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\
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\53\ As Order No. 888 indicates, they may be required to pay the
transmission provider's maximum transmission rate.
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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.54
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\54\ FERC Stats. & Regs. at 31,665-66; mimeo at 89-90.
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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, 1996.55 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.
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\55\ 77 FERC para. 61,025.
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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.56
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\56\ FERC Stats. & Regs. at 31,665; mimeo at 87-88.
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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.[57]
\57\ 76 FERC para. 61,009 at 61,028 (1996).
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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.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.
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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.59
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\59\ FERC Stats. & Regs. at 31,668-79 and 31,686-87; mimeo at
98-129 and 148-51.
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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 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; 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.
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\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).
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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 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.
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\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\
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\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.
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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\
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\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.
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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\
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\66\ See FERC Stats. & Regs. at 31,669-70; mimeo at 101-03.
\67\ 824 F.2d at 998.
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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\
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\68\ See FERC Stats. & Regs. at 31,676-78; mimeo at 120-27.
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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.
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\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.''
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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.
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\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\
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\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.
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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.
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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.
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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).
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\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.
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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.
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\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. * *
*'').
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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 206.82 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.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.84 We disagree. In enacting EPAct,
Congress did not resolve the extent of our wheeling authority outside
the context of sections 211 and 212.85 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
206.86 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 206.87
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\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.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.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).
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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. 888.90 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. [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.'' 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.''
[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. [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.'' 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.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.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.
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.'' 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.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.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.'' 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.'' 103 However, the court
in AGD succinctly dismissed a similar argument:
\103\ Carolina P&L at 35-36.
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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. [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 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.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.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.'' 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 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.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.111 ``In this context, framing the analysis in terms of how
a public utility treats similarly situated customers is not applicable
or instructive.'' 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.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.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.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.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 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.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.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.
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\119\ FERC Stats. & Regs. at 31,688-90; mimeo at 154-58.
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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.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).
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\120\ E.g., SoCal Edison, PSE&G, Carolina P&L.
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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)).121
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\121\ See also CSW Operating Companies.
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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.[122]
\122\ FERC Stats. & Regs. at 31,689-90; mimeo at 158.
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Therefore, the Commission is not compelling a utility to provide
un-
bundled retail transmission service.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.
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\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.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: 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. [ 126]
\126\ 76 FERC at 61,024.
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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.[127]
\127\ FERC Stats. & Regs. at 31,770 n. 514; mimeo at 399 n. 514.
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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,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
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. 130
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\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.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.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).
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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. 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.'' 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.
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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.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.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.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.138
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\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).
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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.139
---------------------------------------------------------------------------
\139\ FERC Stats. & Regs. at 31,693; mimeo at 168-70.
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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.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.[141]
\141\ FERC Stats. & Regs. at 31,694; mimeo at 172.
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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.142
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\142\ FERC Stats. & Regs. at 31,696; mimeo at 178-179.
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(1) Reassignable Transmission Services
The Commission concluded that point-to-point transmission service
should be reassignable, but that network transmission service is not
reassignable.143
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\143\ FERC Stats. & Regs. at 31,696; mimeo at 179.
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(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.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.
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\144\ FERC Stats. & Regs. at 31,696-97; mimeo at 179-80.
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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.145 The Commission, however, did permit mutually
agreeable alternatives to this approach.
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\145\ FERC Stats. & Regs. at 31,697; mimeo at 180-81.
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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).146
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\146\ FERC Stats. & Regs. at 31,697; mimeo at 181.
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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.[147]
\147\ VT DPS at 47-48; see also Valero at 29-31.
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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.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.
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\148\ CCEM makes this argument in its rehearing request of Order
No. 889.
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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.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.150
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\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.
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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.151
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\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.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.
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\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.
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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.153
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\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.154
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\154\ FERC Stats. & Regs. at 31,698; mimeo at 183-84.
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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.155
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\155\ FERC Stats. & Regs. at 31,699; mimeo at 186.
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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.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.
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\156\ FERC Stats. & Regs. at 31,699-700; mimeo at 188.
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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.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.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.
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\158\ FERC Stats. & Regs. at 31,781; mimeo at 431.
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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).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.160
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\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.
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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.161
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\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.162 The Commission
adopted NERC's recommendations for ancillary service definitions and
descriptions with modifications.163
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\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.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.
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\164\ FERC Stats. & Regs. at 31,716; mimeo at 238.
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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.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.
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\165\ FERC Stats. & Regs. at 31,716-17; mimeo at 239.
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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.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.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.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.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 /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.170
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\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.
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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.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.'' 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.
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\171\ FERC Stats. & Regs. at 31,711; mimeo at 222.
\172\ FERC Stats. & Regs. at 31,711; mimeo at 223.
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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.173
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\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.
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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.174 APPA asserts that the narrow
bandwidth imposes obligations on the transmission customer that the
transmission provider does not impose on itself.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 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.176 They fear
that meeting the 1.5 percent bandwidth would require expensive dynamic
scheduling.
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\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.
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Some entities recommend a particular alternative bandwidth.177
TDU Systems suggests a sliding scale as follows. There would be a
bandwidth of 5 percent of scheduled energy for transactions
of 500 MW or less, decreasing to 1.5 percent for
transactions of 5,000 MW or more, with a minimum bandwidth of
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.
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\177\ E.g., TDU Systems, TAPS, NRECA, Wabash, Redding.
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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.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.
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\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.
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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
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 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.179
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\179\ FERC Stats. & Regs. at 31,719; mimeo at 246.
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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.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 206.181
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\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.
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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,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.
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\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.
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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\
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\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.
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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\
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\184\ FERC Stats. & Regs. at 31,720-21; mimeo at 250-52.
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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\
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\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.
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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\
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\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); 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.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.194
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\194\ See FERC Stats. & Regs. at 31,727-28; mimeo at 271-72.
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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.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. 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.197
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\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.198
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\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.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.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.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.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.'' 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.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.'' 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.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.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)).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.209
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\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).
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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, 1996.210 Thus, any economy energy service included in
existing package agreements must be unbundled.
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\210\ FERC Stats. & Regs. at 31,730; mimeo at 277.
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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.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, 1996.212 However, non-economy energy coordination agreements
presented a different situation.
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\211\ FERC Stats. & Regs. at 31,730; mimeo at 277.
\212\ Approximately 300 filings to unbundle this category were
filed by December 31, 1996.
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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.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.214
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\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.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.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.
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\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.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.
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\217\ FERC Stats. & Regs. at 31,730-32; mimeo at 279-86.
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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.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.[219]
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\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.220
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\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.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.
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\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.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. 223
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\222\ FERC Stats. & Regs. at 31,733; mimeo at 288-89.
\223\ FERC Stats. & Regs. at 31,733; mimeo at 289.
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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.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.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,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.
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\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).
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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.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).
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\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.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.
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\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.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.
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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 230
that seek to eliminate the load from their network load ratio
calculation.
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\230\ Behind-the-meter generation means generation located on
the customer's side of the point of delivery.
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(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.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.
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\231\ E.g., NRECA, TDU Systems, Blue Ridge.
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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.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.
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\232\ FERC Stats. & Regs. at 31,736; mimeo at 297.
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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. 888.233 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.
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\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.
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(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. 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.
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\234\ E.g., Utilities For Improved Transition, Florida Power
Corp, VEPCO.
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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\
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\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\
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\236\ FERC Stats. & Regs. at 31,770; mimeo at 398-99.
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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
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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\
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\238\ See FERC Stats. & Regs. at 31,736 and 31,743; mimeo at 297
and 317.
\239\ E.g., TAPS, Central Minnesota Municipal.
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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.
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\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.
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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\
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\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\
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\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.
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\243\ FMPA II at 61,011.
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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\
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\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).
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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.
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\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.
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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\
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\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.
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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.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\
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\250\ E.g., NRECA, TDU Systems, AEC & SMEPA.
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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. [251]
\251\ NRECA at 78-79; TDU Systems at 32.
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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.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.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.
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\253\ FERC Stats. & Regs. at 31,737-38; mimeo at 301-04.
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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.254
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\254\ FERC Stats. & Regs. para. 31,005 (1994).
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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.255
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\255\ See also NE Public Power District.
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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.256
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\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.[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.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.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.260
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\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.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.
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\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.262
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\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.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).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.'' 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.
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\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.'' 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.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.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.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,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).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.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.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.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.275
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\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).
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In order to conform the Final Rule preamble language with the
tariff provisions of Order No. 888,276 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.'' 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.278
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\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.
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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.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.
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\279\ FERC Stats. & Regs. at 31,743-44; mimeo at 319-20.
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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.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.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.
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\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.
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Rehearing Requests
Utility Position
A number of utilities assert that the affiliate discounting
provision is too broad.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.
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\282\ E.g., SoCal Edison, Entergy, Southwestern, PacifiCorp,
Montana Power, AEP, Utilities For Improved Transition, EEI.
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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.283
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\283\ See also Washington Water Power.
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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.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.
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\284\ E.g., Montana Power, Allegheny, Puget.
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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.285 Florida Power Corp asserts that because
communications regarding discounts must be posted on OASIS,
preferential treatment would be readily apparent.
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\285\ See also Florida Power Corp.
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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),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''
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.)
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\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.
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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.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.
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\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.
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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\
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\289\ Thus, there is no need to revise contracts to reflect
later offered discounts.
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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).290
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\290\ See also Valero.
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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.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.
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\291\ Arizona Public Service Company, Order Addressing
Functional Unbundling Issues, 78 FERC para. 61,016 (slip op. at 11)
(1997) (Arizona).
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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.292
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\292\ FERC Stats. & Regs. at 31,745; mimeo at 323-24.
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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.