[Federal Register Volume 59, Number 212 (Thursday, November 3, 1994)]
[Unknown Section]
[Page 0]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 94-27091]
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[Federal Register: November 3, 1994]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 2
[Docket No. RM93-19-000]
Inquiry Concerning the Commission's Pricing Policy for
Transmission Services Provided by Public Utilities Under the Federal
Power Act; Policy Statement
Issued: October 26, 1994.
AGENCY: Department of Energy, Federal Energy Regulatory Commission.
ACTION: Final rule; policy statement.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
issuing this policy statement to announce a general policy regarding
the pricing of transmission services provided by public utilities and
transmitting utilities under the Federal Power Act.
The new policy is designed to allow much greater transmission
pricing flexibility than was allowed under previous Commission
policies.
EFFECTIVE DATE: This policy statement is effective as of October 26,
1994.
FOR FURTHER INFORMATION CONTACT:
James H. Douglass, Office of the General Counsel, Federal Energy
Regulatory Commission, 825 North Capitol Street, NE., Washington, DC
20426, Telephone: (202) 208-2143 (legal issues)
Stephen J. Henderson, Office of Economic Policy, Federal Energy
Regulatory Commission, 825 North Capitol Street, NE., Washington, DC
20426, Telephone: (202) 208-0100 (technical issues)
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 Room 3104, at 941 North
Capitol Street, NE., Washington, DC 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. To access CIPS, set your communications
software to use 300, 1200, or 2400 bps, full duplex, no parity, 8 data
bits and 1 stop bit. CIPS can also be accessed at 9600 bps by dialing
(202) 208-1781. The full text of this order will be available on CIPS
for 30 days from the date of issuance. The complete text on diskette in
WordPerfect format may also be purchased from the Commission's copy
contractor, La Dorn Systems Corporation, also located in Room 3104, 941
North Capitol Street, NE., Washington, DC 20426.E-1
Policy Statement
Issued: October 26, 1994.
The Federal Energy Regulatory Commission (Commission) announces a
new policy regarding the pricing of transmission services provided by
public utilities and transmitting utilities under the Federal Power Act
(FPA).\1\ The new policy is designed to allow much greater transmission
pricing flexibility than was allowed under previous Commission
policies.
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\1\16 U.S.C. 824(e), 796(23).
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Greater pricing flexibility is appropriate in light of the
significant competitive changes occurring in wholesale generation
markets, and in light of our expanded wheeling authority under the
Energy Policy Act of 1992 (EPAct).\2\ These recent events underscore
the importance of ensuring that our transmission pricing policies
promote economic efficiency, fairly compensate utilities for providing
transmission services, reflect a reasonable allocation of transmission
costs among transmission users, and maintain the reliability of the
transmission grid. The Commission also recognizes that advances in
computer modeling techniques have made possible certain transmission
pricing methods that once would have been impractical.
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\2\See 16 U.S.C. 824j, 824k.
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Based on the record developed in this proceeding, the Commission
concludes that there appears to be a variety of workable, non-
traditional transmission pricing methods that offer potential
improvements in fairness, practicality and economic efficiency. For
instance, the Commission believes that distance- sensitive rates using
contract path or flow-based methods will be acceptable if properly
supported.
Accordingly, the Commission will permit more flexibility to
utilities to file innovative pricing proposals that meet the
traditional revenue requirement and will allow such proposals to become
effective 60 days after filing,\3\ as long as they satisfy certain
pricing principles discussed below. We refer to this category of
proposals as conforming proposals. We will also permit utilities to
file pricing proposals that deviate from the traditional revenue
requirement, as long as they meet certain requirements discussed below.
We refer to these filings as non- conforming proposals. Non-conforming
proposals will be permitted to go into effect only prospectively from
the date the Commission determines that such a pricing proposal meets
the statutory requirements of the FPA, i.e., is just and reasonable and
not unduly discriminatory or preferential.
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\3\Whether to suspend such a filing and impose a refund
condition will be decided on a case-by-case basis. See West Texas
Utilities Company, 18 FERC 61,189 (1982).
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In addition to the guidance in this Policy Statement regarding
conforming and non-conforming transmission pricing proposals, there are
two specific subject areas for which we have instituted separate
proceedings, and which may require transmission pricing flexibility.
See Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Notice of Proposed Rulemaking, IV FERC Stats. & Regs.
32,507, 59 FR 35274 (July 11, 1994); Alternative Power Pooling
Institutions under the Federal Power Act, Notice of Inquiry, FERC
Stats. & Regs. ________ (1994). In those proceedings, we are
examining what type of pricing policy is appropriate. We intend to
examine whether any special procedural mechanisms are necessary to
coordinate our pricing policy and filings proposing alternative power
pooling institutions.
I. Introduction
The Commission will consider a broad range of rate design methods,
within a utility's embedded original cost revenue requirement, as
discussed in Section IV. We will also consider proposals that deviate
from a utility's embedded original cost revenue requirement (subject to
certain filing procedures and evaluation criteria), as discussed in
Section V. The U.S. Supreme Court has recognized the Commission's broad
latitude to fix rates. There is no single valid theory of ratemaking.
Under the statutory standard of ``just and reasonable'' it is the
result reached, not the method employed, which is controlling. Duquesne
Light Co. v. Barasch, 488 U.S. 299, 316 (1989) (Duquesne); Federal
Power Commission v. Hope Natural Gas Co., 320 U.S. 591, 602 (1944)
(Hope). As the Court observed in Duquesne:
The designation of a single theory of ratemaking as a
constitutional requirement would unnecessarily foreclose
alternatives which could benefit both consumers and investors.
488 U.S. at 316. Consistent with our broad ratemaking authority, in
this Policy Statement we announce that we will consider various
ratemaking methods to encourage proposals that will produce consumer
benefits.
The Commission's traditional transmission pricing policy has
permitted a public utility providing firm transmission service to
charge rates designed to yield annual revenues equal to the rolled-in
embedded cost\4\ of the utility's integrated transmission grid on a
postage stamp basis (i.e., not distance sensitive), including the
rolled-in costs of any new facilities or upgrades that become part of
the integrated system. For non-firm transmission service, the
Commission has permitted rates to reflect, in addition to the variable
costs of providing the service, a charge up to a 100 percent
contribution to the fixed costs of providing the service, with the
proviso that pricing must reflect the characteristics of the service
provided, e.g., the degree of interruptibility. Traditionally,
transmission rates have been based on a ``contract path'' model, i.e.,
an assumed transmission path from point A to point B, that may or may
not represent the actual flows of power on the grid.
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\4\Embedded cost is generally viewed as including a fair rate of
return on the original cost of facilities, less depreciation, plus
operation and maintenance expenses, and taxes. Embedded costs are
those costs reflected in the utility's books of account.
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In recent years, the Commission attempted to address the industry's
changing needs by modifying its historical transmission pricing
policy\5\ to allow a type of incremental cost pricing.\6\ In order to
provide new or expanded transmission service, a utility may be required
to add expensive transmission assets, which can result in an increase
in rolled-in embedded cost rates. To address this possibility, the
Commission has allowed a utility to charge transmission-only customers
the higher of embedded costs (for the system as expanded) or
incremental expansion costs, but not the sum of the two.\7\ When the
transmission grid is constrained and the utility chooses not to expand
its system, the Commission has allowed a utility to charge the higher
of embedded costs or legitimate and verifiable opportunity costs, but
not the sum of the two. The opportunity costs, in turn, are capped by
incremental expansion costs. This type of pricing has been referred to
as ``or'' pricing or Northeast Utilities pricing.\8\ While ``or''
pricing will continue to be allowed under the Commission's pricing
policy, the Commission is prepared to move beyond ``or'' pricing to
consider other pricing alternatives.
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\5\See Northeast Utilities Service Company (Re: Public Service
Company of New Hampshire), Opinion No. 364-A, 58 FERC 61,070, reh'g
denied, Opinion No. 364-B, 59 FERC 61,042, order granting motion
to vacate and dismissing request for rehearing, 59 FERC 61,089
(1992), affirmed in part and remanded in part sub nom. Northeast
Utilities Service Company v. FERC, Nos. 92-1165, et al., 993 F.2d
937 (1st Cir. 1993), order on remand, 66 FERC 61,332, reh'g denied,
68 FERC 61,041 (1994), appeal pending No. 94-1949 (1st Cir. Sept.
6, 1994); Pennsylvania Electric Company, 58 FERC 61,278, reh'g
denied and pricing policy clarified, 60 FERC 61,034, reh'g denied,
60 FERC 61,244 (1992), affirmed sub nom. Pennsylvania Electric Co.
v. FERC, 11 F.3d 207 (D.C. Cir. 1993) (Penelec).
\6\Incremental cost is the cost of increasing the level of
service provided. In practice, it typically refers to the cost of
additional facilities needed to provide the requested service.
\7\This current pricing policy is based on three goals that the
Commission adopted in the Northeast Utilities case: (1) to hold
native load customers harmless, (2) to provide the lowest reasonable
cost-based price to third-party firm transmission customers, and (3)
to prevent the collection of monopoly rents by transmission owners
and promote efficient transmission decisions.
\8\See supra note 5.
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II. Request for Comments
On June 30, 1993, the Commission issued a notice of technical
conference and request for comments concerning these policies and other
transmission pricing issues. Inquiry Concerning the Commission's
Pricing Policy for Transmission Services Provided by Public Utilities
Under the Federal Power Act, IV FERC Stats. & Regs., Notices 35,024
(1993) (Pricing Inquiry). The Commission received comments and reply
comments from 165 entities, representing a broad cross-section of
parties that participate in, or are affected by, the electric utility
industry. The Commission also held technical conferences on April 8 and
15, 1994, that provided further opportunity for public comment and
discussion. A summary of the comments received in this proceeding that
included proposals for change is presented in Appendix A.\9\
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\9\Appendix A will not appear in the Code of Federal
Regulations.
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Those commenting expressed a variety of opinions on many
transmission pricing issues, including whether transmission rates
should reflect distance sensitivity and whether and how to compensate
for flows over parallel paths. The commenters were nearly unanimous in
their call for the Commission to provide further guidance concerning
acceptable pricing methods. Some commenters indicated that such
guidance would assist the formation of regional transmission groups
(RTGs) by indicating what pricing policies will be acceptable to the
Commission.
While many of the comments expressed dissatisfaction with the
Commission's current pricing policy, the comments indicated no
consensus for any one alternative pricing method. However, the
commenters expressed general agreement that some type of transmission
pricing reform by the Commission is needed. There was a strong
consensus that such reform should: (1) Allow greater pricing
flexibility; (2) provide pricing that is ``transparent''\10\ and easy
to administer; (3) promote economic efficiency, that is, allow
transmission customers to make informed decisions as to the economic
consequences of their choices, and encourage transmission owners to
make efficient use of, and investment in, the transmission grid; (4)
ensure equity and fairness; and (5) facilitate the development of
RTGs.\11\
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\10\We interpret the commenters to mean that transmission
pricing would be identified separately from generation pricing, that
transmission pricing would identify all cost components of the
transmission service (e.g., identify ancillary service costs) and
that pricing information would be readily available to all bulk
power participants.
\11\Two RTG agreements recently filed with the Commission
postpone dealing with the transmission pricing issue by simply
providing that pricing shall be consistent with the Commission's
transmission pricing policy. See Pacificorp et al. (on behalf of
Western Regional Transmission Association), 69 FERC ________
(1994); Southwest Regional Transmission Association, 69 FERC
________) (1994).
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However, there was disagreement regarding the degree to which
reform of transmission pricing should stress administrative simplicity
versus accuracy. Some commenters advocated the continued use of
traditional contract path and postage stamp rates, in part because
these rates are simple to administer. Other commenters proposed
methods, such as distance sensitive and flow-based rates, that may give
better price signals but involve more complexity.
In response to the comments received, the Commission has decided to
revise its policies to permit utilities much greater flexibility. We
are prepared to accept a variety of pricing methods in addition to
Northeast Utilities pricing. Northeast Utilities pricing will still be
acceptable because it fully comports with the pricing principles we
adopt today. However, based on the record developed herein, a variety
of other pricing methods will also be acceptable.
The Commission concludes that greater pricing flexibility is now
required for several reasons. First, exclusive use of methods that
worked reasonably well in the past does not provide sufficient
flexibility to accommodate the evolving needs of transmission owners
and users in a more competitive era.\12\ It is important to gain
practical experience with alternative transmission pricing approaches
in order to assess how best to accommodate the current and future needs
of the industry in providing efficient and reliable power supply as the
industry becomes increasingly competitive. Second, our existing ``or''
pricing policy may not always encourage the most efficient investments
in and use of the transmission grid. Third, regional differences (e.g.,
power flow patterns and population densities) justify a more flexible
policy that can account for such differences. Fourth, a more flexible
pricing policy may be necessary to implement effectively our RTG
policy, which encourages RTGs to deal with a broad range of issues,
including pricing, and which suggests that the Commission, in
appropriate circumstances, will defer to RTG decision-making.\13\ The
Commission is convinced that a more flexible pricing policy can help to
achieve broader policy goals and be implemented in a manner that is
just and reasonable and not unduly discriminatory or preferential.
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\12\See American Electric Power Service Corporation, 67 FERC
61,168 at 61,490 (1994).
\13\Policy Statement Regarding Regional Transmission Groups, 58
FR 41626 (Aug. 5, 1993) III FERC Stats. & Regs. 30, 976 (July 30,
1993) (RTG Policy Statement).
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In developing a more flexible transmission pricing policy, the
Commission's basic premise is that comparable access to efficiently
priced transmission services is critical to the continued development
of a competitive wholesale power market. With this fundamental
underpinning in mind, the Commission has developed several pricing
principles that new pricing proposals should follow. Some of these
principles reflect existing pricing requirements that any new proposal
must continue to follow. Other principles, while important, may have to
be balanced against one another.
Before discussing the pricing principles and specific new
methodologies that may be acceptable, there are several points we would
like to make. First, the Commission believes that improving price
signals is an important goal, but recognizes that trade-offs between
improved price signals and simplicity are inevitable. On one hand,
transmission service is typically a small component of the total cost
of electric service and, therefore, arguably does not merit overly
complex pricing methods.\14\ On the other hand, in many cases
transmission capacity is a scarce and valuable resource, and its
pricing can send signals that promote the efficient siting of
generation facilities and efficient decisions as to the dispatch of
generation. In addition, new technological advances, particularly in
computer technology, have made certain innovative pricing methodologies
workable in practice. We therefore must balance the sometimes competing
goals of better price signals and simplicity when evaluating any new
pricing methodologies.
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\14\Historically, transmission plant has represented less than
12 percent of total electric plant in service for major investor-
owned Electric Utilities and generally less than 6 percent of the
cost of electricity to end users. (Derived from cost data in 1992
Energy Information Administration Financial Statistics of Major
Investor-Owned Electric Utilities.)
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Second, the Commission also recognizes that it must move beyond
certain precedent in order to entertain alternative pricing proposals.
For example, instead of requiring a single postage stamp rate for
transmission over the integrated transmission system of a corporation,
such as a holding company system with several affiliated operating
companies,\15\ we will now entertain proposals such as zonal rates\16\
that take distance within the corporation into account, provided that
such proposals are consistent with the pricing principles that we adopt
today.\17\ Having analyzed new methodologies presented in the record,
we believe that some departures from our traditional integrated system
pricing requirement will be supportable under the FPA if appropriately
developed.
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\15\See, e.g., Southern Company Services, 55 FERC 61,173
(1991), order on reh'g, 58 FERC 61,093 (1991), aff'd, Alabama Power
Company v. FERC, 993 F.2d 1557 (D.C. Cir. 1993).
\16\Under zonal rates, a utility's facilities are divided
(disaggregated) into a number of zones. The total cost assigned to
any request for transmission service would depend on the number of
zones traversed and the rate for each zone.
\17\If a utility, or public utility holding company system,
proposes to disaggregate its integrated transmission system into
distinct components (or zones) for purposes of developing
transmission rates for third parties, it must apply the same
approach consistently and uniformly across the entire system for all
uses of the system, including its own uses.
We caution that any such zonal approach or other disaggregated
approach would also need to appropriately recognize all flows on the
system. For example, if flows are used to allocate costs on some
lines, flows should be used to allocate costs for all remaining
lines in the same way; e.g., it would not be acceptable to presume
that each transmission customer proportionally uses and relies upon
all remaining lines of the integrated system.
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Third, as previously noted, several commenters urged the Commission
to provide a framework for reforming pricing that would supplement the
Commission's RTG Policy Statement. The Commission continues to believe
that it would be appropriate for RTGs to address transmission pricing.
We anticipate that the pricing flexibility provided herein, and our
willingness to give appropriate deference to RTG decisions, will not
only encourage the development of RTGs, but will also encourage RTGs to
address transmission pricing, including regional issues affecting such
pricing.
Finally, we do not want our policy to be so rigid that utilities
will be prohibited from proposing pricing alternatives that may deviate
from the traditional revenue requirement. Because transmission remains
a natural monopoly, we believe it will be difficult for transmission
owners to support such pricing under the FPA, particularly market-based
transmission rates. However, we believe that it would be shortsighted
to foreclose completely consideration of such non-conforming proposals.
The electric utility industry of today is very different from the
electric utility industry that existed only 20 years ago and even five
years ago. Just as we today change our policies to reflect recent
changes, we must remain flexible if we are to respond to future
changes. Accordingly, we detail procedures and standards below that
will be used in evaluating transmission pricing proposals that do not
conform to the traditional revenue requirement.
We now turn to the requirements of the FPA and the pricing
principles that we have developed consistent with those requirements.
III. Transmission Pricing Principles
Transmission pricing must adhere to the FPA requirement that
transmission rates be just and reasonable and not unduly discriminatory
or preferential. This requirement is found in sections 205, 206, and
212. In addition, section 212(a) requires that wholesale transmission
rates for services ordered under section 211 must:
Permit the recovery of all costs incurred in connection
with the transmission services and necessary associated services,
including, but not limited to, an appropriate share, if any, of
legitimate, verifiable and economic costs, including taking into
account any benefits to the transmission system of providing the
transmission service, and the costs of any enlargement of transmission
facilities;
Promote the economically efficient transmission and
generation of electricity; and
To the extent practicable, ensure that costs incurred in
providing the wholesale transmission services, and properly allocable
to the provision of such services, are recovered from the applicant for
the 211 order and not from a transmitting utility's existing wholesale,
retail, and transmission customers.
Consistent with these statutory requirements, which give the Commission
discretion in setting rates within the zone of reasonableness, and in
light of the comments received in response to the Pricing Inquiry, we
have formulated five principles that will guide our approval of pricing
for both firm and non-firm transmission services in the future. The
Commission believes these principles comport with the statutory
requirements of sections 205, 206 and 212 of the FPA, and, in the
interest of developing a uniform transmission pricing policy, we will
apply these same principles to the pricing of transmission service
whether that service is provided under section 205, 206, or 211 of the
FPA.
The first two principles reflect fundamental requirements
previously established by the Commission. A conforming proposal is one
that meets the first principle, i.e., it proposes pricing that meets
the traditional revenue requirement. A conforming proposal must also
meet the second principle, i.e., it must reflect comparability. As to
the other three principles, however, these reflect goals that an
applicant with a conforming proposal must try to meet, but that
ultimately may need to be balanced against one another in the
Commission's determination of whether the proposed rates are just and
reasonable.
A non-conforming proposal is one that does not meet the first
principle, i.e., it does not propose pricing that meets the traditional
revenue requirement. However, a non-conforming proposal must meet the
second principle, i.e., it must reflect comparability. If a non-
conforming proposal does not clearly demonstrate that the comparability
requirement is met, it will be rejected. As to the remaining three
principles, these reflect goals that an applicant with a non-conforming
proposal must try to meet, but that may need to be balanced against one
another. In addition, as part of its balancing, the Commission will
consider the extent to which the first principle is not met.\18\
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\18\A pricing proposal that deviates from cost only slightly may
be easier to justify than one that results in prices several times
cost.
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We discuss these principles in detail below.
1. Transmission Pricing Must Meet the Traditional Revenue Requirement
For conforming proposals, transmission prices must be based on the
costs of the transmission service provided. The process of determining
transmission prices involves three distinct steps. First, a utility
must determine its total company revenue requirement, the capital
component of which traditionally has been measured by embedded
(depreciated original) cost. Second, a utility must allocate among
individual customers or classes of customers that portion of the total
revenue requirement that is attributable to providing transmission
services, in a manner which appropriately reflects the costs of
providing transmission service to such customers or classes of
customers. Finally, the utility must design rates to recover those
allocated costs from each customer class.
Different customers may pay different rates if they use the system
in different ways. In the aggregate, however, rates are designed so
that a transmission owner meets, but does not exceed, its revenue
requirement. That is, it should be able to collect revenues from all
its customers equal to the sum of its prudently incurred embedded
costs, including return on capital.
There are two reasons for requiring transmission pricing to meet
the traditional revenue requirement. First, it appears that
transmission will remain a natural monopoly for the foreseeable future.
It is unlikely that market-based prices for monopoly services,
especially for firm transmission service, could be justified under the
FPA at the present time, under the current industry structure. However,
it is clear that there is no single appropriate ratemaking method under
the FPA. The end result is the appropriate yardstick against which to
measure the legality of a rate order, not the ratemaking method. Thus,
although no single ratemaking method is necessarily favored by the FPA,
this pricing principle will ensure that transmission users pay a just
and reasonable price for transmission services and that transmission
owners, while being appropriately and adequately compensated,\19\ will
not be able to exercise their market power to collect exorbitant rates.
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\19\Duquesne, 488 U.S. at 316; Bluefield Water Works &
Improvement Co. v. Public Service Commission of the State of West
Virginia, 262 U.S. 679 (1923); Hope, 320 U.S. at 602.
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Second, we believe that pricing within an embedded cost revenue
requirement provides adequate incentives for transmission owners to
provide comparable transmission services, as long as the transmission
owner has the opportunity for full cost recovery. When upgrades are
required, the transmission owner may incur significant expenses related
to planning and siting new facilities. For example, a utility may be
required to pay for environmental mitigation associated with the
construction of new transmission facilities. Such costs will be
recoverable by the transmission owner if they are prudently incurred.
In addition, under the traditional revenue requirement principle,
transmission owners clearly may, with appropriate support,\20\ recover
the legitimate and verifiable costs of services they provide that are
ancillary to transmission services, such as load following, reactive
power compensation, and backup power services. However, transmission
customers should also be permitted to provide these services themselves
or to obtain them from someone else if this is feasible.
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\20\See Northern States Power Company (Minnesota and Wisconsin)
Opinion No. 383, 64 FERC 61,324 (1993), reh'g pending (reactive
power).
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Finally, as discussed in Section IV below, we intend to allow
significant latitude and a wide variety of non-traditional rate design
proposals, within a cost cap based on the total company revenue
requirement.
2. Transmission Pricing Must Reflect Comparability
Any new transmission pricing proposal, conforming or non-
conforming, must meet the Commission's recently announced comparability
standard. In American Electric Power Service Corporation (AEP), 67 FERC
61,168 (1994), the Commission articulated a new standard for judging
whether access to transmission services is unduly discriminatory, or
anticompetitive. The Commission noted that ``[a]n open access tariff
that is not unduly discriminatory or anticompetitive should offer third
parties access on the same or comparable basis, and under the same or
comparable terms and conditions, as the transmission provider's uses of
its system.''\21\ This principle has been applied to all open access
tariffs filed since AEP, as well as to transmission services provided
by RTGs.\22\
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\21\67 FERC at 61,490.
\22\See PacifiCorp, et al. (on behalf of Western Regional
Transmission Association), 69 FERC ______; Southwest Regional
Transmission Association, 69 FERC at ______.
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There is a relationship between price and quality of service (i.e.,
in general, higher quality service costs more). In Florida Municipal
Power Agency v. Florida Power & Light Co., 67 FERC 61,167 at 61,482
(1994) (FMPA), the Commission stated, ``[s]ince FMPA wants to be able
to use the transmission system as freely as does Florida Power, it must
pay a rate that reflects that equality.'' As a result of the
relationship between quality of service and price discussed most
recently in FMPA, and the growing importance of service comparability,
we will require that pricing be comparable. Comparability of service
applies to price as well as to terms and conditions. Comparability of
transmission pricing involves a ``golden rule of pricing''--a
transmission owner should charge itself on the same or comparable basis
that it charges others for the same service.\23\
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\23\There is a similar ``golden rule or access''--provide the
same or comparable services to others as you provide yourself.
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This golden rule has several implications. First, for purposes of
setting FERC-jurisdictional rates, costs must be allocated between
jurisdictional and non-jurisdictional customers in a consistent way, to
determine the cost responsibility of the two sets of customers.\24\
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\24\The Commission is not in any way suggesting any interference
with state authority to determine the appropriate ratemaking
methodology for bundled retail sales.
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Second, when a utility uses its own transmission system to make
off-system sales, it should ``pay'' for transmission service at the
same price that third-party customers pay for the same service, and
credit the transmission revenues to its native load customers. This
treatment restricts the transmission owner's ability to gain an unfair
advantage in the bulk power market by selling itself transmission
service at a discount that would be subsidized by native load and
transmission-only customers.\25\
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\25\In PSI, for example, the Commission required that PSI take
transmission service under its own transmission tariff when making
market-based power sales. The Commission adopted this approach to
prevent PSI from using its transmission ownership to exercise an
unfair competitive advantage in wholesale power markets. Public
Service Company of Indiana, Inc., Opinion No. 349, 51 FERC 61,367
at 62,201 (1990), order on rehearing, PSI Energy, Inc., 52 FERC
61,260, order granting clarification, 53 FERC 61,131 (1990),
appeal dismissed sub nom. Northern Indiana Public Service Co. v.
FERC, 954 F.2d 736 (D.C. Cir. 1992).
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Pricing comparability does not mean that the Commission is
endorsing an end result in which there are no differences in prices
paid by various customers. For example, the Commission is not
suggesting that prices must be based on highly aggregated costs so that
all customers face a uniform rate per kWh of service. Rather, we are
receptive to pricing proposals that disaggregate costs in order to give
better price signals to all users of the system--third parties and the
transmission owner itself. Such disaggregation still permits different
customers to pay different prices. Pricing comparability does not rule
out such a result.
Finally, comparability of pricing includes certainty of pricing. A
transmission customer should have pricing certainty comparable to that
of the transmitting utility, e.g., the same transmission pricing
certainty for long-term power contracts as the transmitting utility
has.
3. Transmission Pricing Should Promote Economic Efficiency
Section 212(a) of the FPA, as amended by EPAct, states that
transmission pricing should promote economically efficient generation
and transmission of electricity.\26\ In our view, this means that
transmission pricing should promote good decision-making and foster:
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\26\16 U.S.C. 824k(a).
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Efficient expansion of transmission capacity;
Efficient location of new generators and new load;
Efficient use of existing transmission facilities,
including the efficient allocation of constrained capacity through
appropriate market clearing mechanisms; and
Efficient dispatch of existing generating resources.
To the extent practicable, transmission rates should be designed to
reflect marginal costs,\27\ rather than embedded costs, in a manner
consistent with the remaining principles. We favor marginal cost prices
in order to promote efficient decision-making by both transmission
owners and users.\28\ In the short-run, marginal transmission costs are
primarily line losses and, when lines are congested, opportunity costs.
In the long-run, marginal transmission costs include all the costs of
the transmission system and support services. The Commission recognizes
the complexity of estimating marginal cost on the transmission grid and
of implementing pricing that follows marginal transmission costs, but
we encourage experimentation in this area.\29\ On a case-by-case basis,
we will balance the desirability of more economically efficient price
signals against the additional complexity of implementing such pricing.
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\27\Alfred Kahn, infra n.28, defines marginal cost as ``[t]he
cost of producing one more unit; it can equally be envisioned as the
cost that would be saved by producing one less unit.''
\28\See 1 Alfred E. Kahn, The Economics of Regulation 63-86.
\29\Such proposals should be fully supported, with as much
detail as possible. See New England Power Company, Opinion No. 352,
52 FERC 61,090 (1990), reh'g denied, Opinion No. 352-A, 54 FERC
61,055 (1991), aff'd sub nom. Town of Norwood, Massachusetts v.
FERC, 962 F.2d 20 (D.C. Cir. 1992).
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4. Transmission Pricing Should Promote Fairness
As a general matter, transmission pricing should be fair and
equitable. This has two important implications. First, the EPAct
requires that, to the extent practicable, existing wholesale, retail
and transmission customers should not pay for the costs incurred in
providing wholesale transmission services ordered under section 211.
Similarly, we do not believe that third-party transmission customers
should subsidize existing customers. We believe this principle should
apply equally to transmission services under both section 211 and
sections 205 and 206.
A second implication of the fairness principle is that economic
harm that could be created during a period of transition from one
pricing approach to another should be mitigated to the extent
practicable. Solutions to any transition problems arising from pricing
reform should balance fairness considerations associated with any
reform against the potential efficiency improvements, and should
mitigate the hardships arising from any reform. The major purpose of
transmission pricing reform should be to provide more efficient price
signals, particularly for new transmission uses, and not simply to
reallocate sunk costs.
5. Transmission Pricing Should Be Practical
Transmission pricing should be practical and as easy to administer
as appropriate given the other pricing principles. A user should be
able to calculate how much it will be charged for transmission service.
Some pricing proposals may be so complex that they are difficult to
understand and analyze. Such complexity, while not fatal, should be
balanced by efficiency gains or other advantages produced by such
complexity.
IV. Guidance Regarding Pricing Proposals That Conform to the
Traditional Revenue Requirement
In addition to the five general principles above, the Commission
provides guidance on specific pricing proposals, including examples of
acceptable pricing approaches and clarification of limitations on
pricing flexibility.
It is important for those involved in transmission pricing
discussions and negotiations to have a common understanding of the
attributes of various pricing proposals. For example, various parties
advocate the use of ``megawatt mile'' pricing. Several distinct pricing
proposals carry the same ``megawatt mile'' label. Therefore, those
proposing transmission pricing reform must provide a clear explanation
of their proposal.
As the industry considers possible pricing reform, the following
three attributes of any transmission pricing method should be specified
to provide a common framework for analysis:
The method for measuring cost for purposes of rate design:
embedded cost, incremental cost, the Commission's current ``or''
policy, long-run marginal cost, or short-run marginal cost;
The method for treating power flows: contract path or
flow-based approach; and,
The method for grouping transmission facilities: corporate
postage stamp versus more disaggregated approaches, such as zones, or
line-by-line methods.\30\
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\30\Under a line-by-line pricing method, the costs of each
transmission line, or segment, are allocated to individual
transmission transactions, based on the usage each transaction makes
of each line or segment.
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We anticipate that a wide variety of pricing proposals may be
reconciled with the traditional revenue requirement. In theory,
acceptable cost-based pricing that satisfies our principles could be
designed for many combinations of these possible attributes. For
example, prices could reflect incremental cost (the first attribute),
be based on flow (the second attribute), and be allocated on a line-by-
line basis (the third attribute). A different approach is taken by
changing any one of the attributes, e.g., zones instead of lines.
Therefore, many varieties of cost-based pricing are possible.
We fully intend to be flexible and to consider innovative,
conforming pricing approaches that accommodate the changing needs of
the competitive bulk power market. This applies to pricing for firm as
well as non-firm transmission services. The pricing principles set out
in the prior section are intended to guide RTGs and individual
utilities in their consideration of new approaches. To provide further
guidance, we discuss below examples of new cost-based pricing methods
that we believe can be made consistent with our principles. These
examples are intended to be illustrative. Other approaches also may be
consistent with the principles. In all cases, we emphasize that pricing
reform must have a purpose consistent with the principles. We want
transmission pricing that supports good and consistent decisionmaking
by transmission system users and owners.
A. Examples of Specific Pricing Methods That Conform to the Traditional
Revenue Requirement
The following pricing approaches are examples of methods that the
Commission would find acceptable, assuming an adequate showing by the
utility. In this context, a conforming method is one that clearly meets
the first two fundamental requirements and demonstrates that it is
capable of satisfying the other three pricing principles (which
ultimately may need to be balanced against one another in the
Commission's determination of whether the proposed rates are just and
reasonable). Of course, the rates resulting from its use must be shown
to be just, reasonable and not unduly discriminatory or preferential.
(1) Examples of Acceptable Transmission Pricing by an Individual
Utility
A variety of pricing proposals from an individual utility could be
acceptable under the five pricing principles. The range of possible
approaches includes various combinations of: (1) a traditional contract
path approach or a flow-based approach; (2) costs aggregated at the
utility level, at a zonal level, or at the line-by-line level; and (3)
various cost concepts for rate design, such as embedded cost, ``or''
cost, incremental cost, or short-run marginal cost. Not all of these
possible combinations, however, would necessarily satisfy our
principles.
Examples of pricing reform that the Commission would approve if
proposed by an individual utility and if they satisfy our principles
include:
Zonal ``or'' pricing based on power flows from zone to
zone within a utility, or within the members of a holding company
system. Zonal rates should be supported by showing the use made of
separate zones by an individual transaction. Such rates should be
supported by an explanation of the data base required and the computer
modeling needed to implement it.
Flow-based line-by-line rates, based on embedded costs
``or'' pricing. Such rates should be supported by an explanation of the
data base required and the computer modeling needed to implement it.
``Or'' pricing, at the corporate level using the
traditional contract path approach. This is the current Commission
standard and remains an acceptable pricing policy that satisfies our
pricing principles.
(2) Examples of Acceptable Transmission Pricing by an RTG
The Commission will provide substantial latitude for innovative,
conforming pricing proposals by a regional transmission group that
meets the requirements of our RTG Policy Statement.\31\ We will give
more latitude to RTGs than to individual utilities. This is for two
reasons. First, an RTG represents the combined interests of both
transmission owners and transmission users, as well as the appropriate
participation of state authorities, so pricing proposals are likely to
represent an appropriate balancing of those interests. Second, the more
attractive proposals for treating regional loop flow problems work
better if all the utilities in the region use the same method.
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\31\Policy Statement Regarding Regional Transmission Groups, 58
FR 41626 (Aug. 5, 1993), III FERC Stats. & Regs. 30,976 (July 30,
1993); See also PacifiCorp, et al. (on behalf of Western Regional
Transmission Association), 69 FERC at ________; Southwest Regional
Transmission Association, 69 FERC at ________.
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An RTG could propose any pricing reform that is open to an
individual utility and also other reforms that address the loop flow
issue. Many approaches to reforming transmission pricing that were
suggested in the record of the Pricing Inquiry address the loop flow
issue and appear to require a regional approach. From the comments, the
Commission discerns two major alternatives to traditional contract path
pricing that RTGs could choose for dealing with loop flow:
``Enhanced'' contract path pricing, which improves the
contractual institutions underlying traditional contract path
trading;\32\ and
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\32\``Enhanced contract path'' refers to any approach intended
to reconcile capacity rights between points of receipt and delivery
and actual power flows on a network of lines.
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Flow-based pricing, which refers to pricing designed to
reflect the actual or projected power flows associated with a
transaction.
Cost-based pricing could be designed to accommodate either of these
alternatives. Examples of pricing reform based on a flow-based approach
that the Commission would look approvingly on if proposed by an RTG and
if consistent with our principles include:
A MW-mile method, which could be implemented in one of
several ways. For example, it could be based on ``or'' pricing and
line-by-line power flows. Alternatively, a MW-mile approach could be
based on embedded cost for the whole company, allocated as the ratio of
transaction-specific megawatt-miles to total megawatt-miles.
Postage-stamp ``or'' ratemaking at the utility level that
is combined with power flow analysis to determine the compensation due
to all transmission owners on the parallel paths. This would be a
departure from the current contract path approach.
Zonal ``or'' pricing based on power flow analysis to
determine the use a transaction makes of the facilities in each zone.
Short-run marginal cost pricing with transmission prices
based on line-by-line losses and opportunity costs caused by power flow
constraints.
RTGs may be able to design a pricing approach that combines
elements of flow-based pricing with elements of contract path pricing.
An example might be contract-path pricing for capacity rights to engage
in long-term firm transactions combined with flow-based pricing for
short-term, nonfirm transactions that are not covered by such rights.
As can be seen from these examples, the Commission will provide RTGs
substantial flexibility in choosing among a wide range of pricing
approaches.
(3) Examples of Unacceptable Transmission Pricing
As discussed above, any pricing proposal, even a proposal that does
not conform to the traditional revenue requirement, must meet the just
and reasonable standard of the FPA. Below we list two types of pricing
proposals which we find unacceptable.
Postage-Stamp ``And'' Pricing: Some utilities have
proposed so-called ``and'' pricing, which would add an embedded cost
rate to an incremental cost rate for the same service over the same
facilities. The proposals have been based on traditional postage stamp
ratemaking for which costs are aggregated at the utility level. This
type of pricing has been found by the Commission to be unjust and
unreasonable.\33\ We cannot see how such an approach is consistent with
either our fairness principle or our efficiency principle.\34\
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\33\See Penelec, supra n.5.
\34\The flexibility that we endorse in this Policy Statement
regarding cost disaggregation, among other things, addresses the
industry's underlying concerns regarding ``or'' pricing. That is,
while we cannot justify pricing that purports to recover two
measures of a single cost, allowing the entity to account for costs
on a disaggregated basis would permit separate pricing for separate
facilities or small groupings of facilities. Hence, we would
entertain proposals for flow-based line-by-line ``or'' pricing. This
would permit the use of embedded costs for some lines when this is
the higher of embedded or incremental costs, and the use of
incremental cost for other lines when this is the higher of embedded
or incremental costs.
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Pricing by Individual Utilities to Account for Loop Flow:
While individual utilities may propose new and innovative pricing
methods that seek to apportion transmission costs on the basis of
scheduled flows (e.g., zonal or line-by-line methods), we also believe
that it would be inappropriate for individual utilities to reform their
own approach to transmission pricing in a way that is inconsistent with
regional practices regarding unscheduled or inadvertent flows (loop
flow).\35\ We are concerned that individual public utilities may
propose approaches to loop flow pricing that lead to a patchwork of
mutually inconsistent loop flow pricing methods within a region.
Accordingly, a utility's proposal to use flow-based pricing generically
to recover the costs of unscheduled inter-utility power flows will be
treated as a non-conforming proposal if it is inconsistent with
regional loop flow practices, such as use of a contract path
convention.\36\
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\35\Of course, such individual utility pricing may be
appropriate if there are no objections to the loop flow solution
from any affected neighboring utilities or transmission customers.
\36\However, a public utility may seek on a case-by-case basis
relief from the Commission, including appropriate compensation, in
situations in which it is experiencing severe unscheduled loop flows
on its system because of specific power transactions by other
neighboring utilities and it has been unable to resolve the problem
through existing industry mechanisms. See American Electric Power
Service Corp., et al., 49 FERC 61,377 at 62,381 (1989).
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V. Pricing Proposals That Do Not Conform to the Traditional Revenue
Requirement
The Commission clearly prefers pricing proposals that are designed
not to exceed the traditional revenue requirement. As noted, we believe
that given the current industry structure it will be difficult to
justify non-conforming proposals. In addition, we believe that the
flexibility permitted under this revised transmission pricing policy
should be adequate to satisfy the needs of today's electric utility
industry, particularly given the current structure of the industry.
Nevertheless, the electric utility industry is continuing to evolve\37\
and we must ensure that our policies do not impede the continued
development of competitive bulk power markets, or the development of
new market structures and transmission arrangements. The Commission
will consider pricing proposals necessary to accommodate such
developments. Some of the proposals discussed in this proceeding may
exceed the traditional embedded cost revenue requirement. Such
proposals will be considered provided they meet certain filing
procedures and evaluative criteria. We will provide two procedural
avenues for considering non-conforming proposals. We will also provide
guidance on the type of evidentiary showing necessary to support such
proposals.
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\37\In recent months, the pace of change in the electric
industry has increased dramatically. Certain state proceedings on
industry restructuring, as well as proceedings before this
Commission, have contributed to the development of innovative
proposals by both industry participants and academicians. These
evolutionary changes support the need for flexibility and the need
to permit non-conforming pricing proposals.
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A. Procedures for Proposals That Do Not Conform to the Traditional
Revenue Requirement
Any public utility that seeks non-conforming pricing must have on
file with the Commission an open access transmission tariff offering
comparable services. Such comparability tariff must have been accepted
for filing by the Commission before a non-conforming pricing proposal
will be considered. Moreover, utilities proposing non-conforming
transmission pricing must submit such pricing proposals either: (a) in
conjunction with a section 205 conforming transmission pricing proposal
(the non-conforming proposal would be reflected as alternative ``pro
forma'' rate sheets to the conforming proposal); or (b) in a petition
for declaratory order.
(1) Alternative ``Pro Forma'' Rate Sheets
Under this procedure, the Commission and interested parties would
review the non-conforming proposal in conjunction with review of a
companion conforming pricing proposal.\38\ The conforming proposal
would be subject to the notice and suspension procedures of section
205. The non-conforming proposal would not. The non-conforming proposal
would be litigated at the same time as the conforming proposal, but
could not take effect, if at all, until the end of the proceeding. If,
at the end of the proceeding, the Commission determines that the
alternative, non-conforming rate proposal is acceptable under the FPA,
the Commission will allow the utility to make a compliance rate filing,
and the rates will be put into effect prospectively.
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\38\See Pacific Gas Transmission, 66 FERC 61,384, reh'g denied,
67 FERC 61,247 (1994), reh'g pending.
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This procedure will permit the Commission to determine the extent
to which the proposal deviates from the traditional revenue
requirement, which may be necessary in determining whether the other
features of the proposal are sufficient to offset this. It will also
permit an examination of how risk, and hence cost of capital, will vary
under the conforming and non-conforming proposals. Another benefit of
the alternative ``pro forma'' rate sheets procedure is that the utility
would be able to implement the non-conforming pricing, assuming it was
just and reasonable, immediately following the Commission's final
order.
(2) Declaratory Order Petition
A utility that wishes to have the Commission consider a non-
conforming pricing proposal separate from a rate proceeding may bring
the matter to the Commission via a petition for declaratory order. Of
course, if the Commission found that the utility's proposal met the
statutory criteria, the utility would still need to file a rate
reflecting the proposal pursuant to FPA section 205. Presumably the
section 205 proceeding would be straightforward (i.e. akin to a
compliance filing), however, since the Commission would have already
addressed the merits of the proposal in the declaratory order.
B. Criteria for Evaluating Proposals That Do Not Conform to the
Traditional Revenue Requirement
Utilities proposing non-conforming transmission pricing must fully
support such proposals. The utility must supply a complete discussion
of how the proposal is intended to take account of the pricing
principles. The Commission will consider the relative weight of each
pricing principle as applied to the facts of each case. We will hold
the comparability principle inviolate, however. Absent such support,
the Commission will summarily reject the non-conforming proposal even
if the utility has agreed to the procedural requirements set forth
above.
We will also summarily reject non-conforming proposals that do not
submit information showing that the proposal can be expected to:
(a) Produce greater overall consumer benefits than a conforming
proposal; and
(b) Promote competitive bulk power markets.\39\
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\39\The reason we are providing flexibility to consider non-
conforming transmission pricing proposals is because we do not want
to reject out of hand innovative proposals that could benefit
ratepayers. However, we do not intend to waste resources considering
proposals whose sole purpose is to provide more revenue to the
transmitting utilities. We will summarily reject such proposals.
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At a minimum, utilities proposing non-conforming transmission
pricing must make a showing of benefits to a broad cross-section of
consumers which achieve the following:
(i) Greater access and customer choice;
(ii) Projected price decreases to customers of delivered power; and
(iii) Service flexibility and available products to meet customer
needs.
As noted, utilities should also explain how the non-conforming proposal
promotes competitive bulk power markets.
C. Guidance Regarding Proposals That Do Not Conform to the Traditional
Revenue Requirement
We believe that a non-conforming proposal that results from a
diverse group such as an RTG, with fair and nondiscriminatory
governance and decisionmaking procedures, would more easily be found
just and reasonable than a non-conforming proposal from an individual
utility, for the same reason we would afford more deference to a
conforming RTG transmission pricing proposal than an individual utility
conforming proposal.
Although the Commission has been willing, under appropriate
circumstances, to permit market-based pricing for sales of generation,
the Commission intends to treat market-based transmission rate
proposals as non-conforming. Such rates obviously are not cost-based
and the Commission does not believe market-based transmission pricing
is appropriate at this time. Although the transmission system has
multiple owners, the basic provision of firm transmission service is
not competitive in most, if not all, circumstances. Rather, each owner
can exert considerable market power by controlling the access, pricing
and expansion of its portion of the grid. In addition, regulatory
approval for new transmission lines is increasingly difficult to obtain
and franchised owners are typically the only entities that possess
rights of eminent domain. In these circumstances, unlike for sales of
generation, the Commission cannot rely on competitive market forces to
discipline prices for firm transmission service. Accordingly, any
transmission owner advocating a market-based transmission pricing
method must demonstrate how it has alleviated these serious concerns.
Some cost-based pricing approaches adhere to a traditional embedded
(depreciated original) cost revenue requirement more closely than
others. Replacement cost methods and long-run marginal cost methods of
pricing, for example, may result in revenue levels that would exceed
the traditional revenue requirement. Pricing methods designed to allow
a transmission owner to recover more than its traditional revenue
requirement (depreciated original cost) are non-conforming and would
need to satisfy the procedures and criteria for non-conforming
proposals.
VI. Alternative Institutions and Associated Pricing
The Commission is aware that industry participants have begun to
discuss alternative institutional arrangements, such as ``pool
companies'' and ``transmission companies.'' Some of these institutions
apparently are intended to facilitate efficient wholesale power
trading, and may require alternative approaches for the pricing of
transmission services. We believe that these alternative institutions
hold great potential. They may assist in the resolution of some
difficult federal-state jurisdictional issues and in developing
mechanisms for resolving or minimizing stranded cost issues. While we
are encouraged that such ideas are under discussion, and are open to
considering the particular pricing needs of alternative institutions,
these concepts are currently in an early, formative stage. The concepts
associated with these ideas have not been adequately explored in this
pricing docket or in any other Commission forum. Therefore, concurrent
with issuing this Policy Statement, we are opening a separate docket to
initiate an inquiry regarding alternative power pooling institutions
and their particular pricing needs.\40\
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\40\See Alternative Power Pooling Institutions under the Federal
Power Act, Notice of Inquiry, FERC Stats. and Regs. ________.
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VII. Conclusion
The transition to a competitive wholesale bulk power market depends
on the availability of comparable transmission services. Comparable
transmission service, in turn, must have appropriate prices, terms and
conditions. To that end, the Pricing Inquiry has provided the basis for
a productive dialogue among the various entities affected by and
participating in the transition to a post-EPAct competitive bulk power
market, including transmission owners, transmission users, and Federal
and state regulators.
It is critical that transmission services be priced in a manner
that appropriately compensates transmission owners and creates adequate
incentives for system expansion when such expansion is efficient. Of
course, any transmission pricing proposal will have to be evaluated
under the standards of the FPA. The Commission must ensure that any
such proposal is just, reasonable, and not unduly discriminatory or
preferential. A great many of the approaches discussed in this
proceeding have the potential to provide better (i.e., more efficient)
price signals. But they also have the potential to complicate and
prolong the process of determining appropriate rates for transmission
services.
This Policy Statement provides a framework for understanding these
competing interests, as well as a basis for continuing the transmission
pricing dialogue. The Commission has consciously avoided endorsing any
particular commenter's specific pricing methodology. Instead, the
Policy Statement attempts to provide guidance while still encouraging
industry efforts at innovation. Indeed, a great many of the proposals
that were submitted during the Pricing Inquiry are highly theoretical
and would need to be tested and evaluated in the context of individual
cases.
The commenters in the Pricing Inquiry almost unanimously requested
that the Commission allow flexibility. To that end, the Commission has
attempted to provide pricing principles and general guidance that allow
broad experimentation consistent with federal law and the physics of
transmission. Certain experiments, particularly pricing methods that
attempt to recognize loop flow, clearly require regional involvement
and cooperation if they are to be effective. RTGs are encouraged to
address such issues as pricing reform and loop flow.
The Commission encourages filing utilities and new groups that may
form, such as RTGs and pool companies, to work closely with state
regulatory authorities in developing transmission pricing policy. The
Commission is committed to cooperating with all affected parties,
especially state regulatory authorities, to ensure that any such
pricing reform is implemented in an equitable manner and facilitates an
orderly transition to a fully competitive bulk power market. Our
pricing principles are expected to provide the foundation for the
industry to continue its exploration of transmission pricing reform.
Finally, the Commission in this Policy Statement has proposed
procedures under which non-conforming pricing proposals will be
considered. We believe these procedures are flexible enough to permit
utilities to propose non-conforming pricing innovations which they
believe will benefit ratepayers and promote the development of a
competitive bulk power market.
The Commission is making this Policy Statement effective
immediately. It is based on the voluminous record developed to date in
the Pricing Inquiry. We will accept motions for reconsideration
submitted within 30 days in order to help us refine the principles
established herein and to provide an opportunity to respond to any
questions or clarify any ambiguity. We will apply the Policy Statement
to transmission pricing proposals submitted in individual cases filed
after the date of this Policy Statement.
List of Subjects in 18 CFR Part 2
Administrative practice and procedure, Electric power, Natural gas,
Pipelines, Reporting and recordkeeping requirements.
By the Commission.
Lois D. Cashell,
Secretary.
In consideration of the foregoing, the Commission amends Part 2,
Chapter I, Title 18 of the Code of Federal Regulations as set forth
below.
PART 2--GENERAL POLICY AND INTERPRETATIONS
1. The authority citation for Part 2 continues to read as follows:
Authority: 15 U.S.C. 717-717w, 3301-3432; 16 U.S.C. 792-825y,
2601-2645; 42 U.S.C. 4321-4361, 7101-7352.
2. Part 2 is amended by adding Sec. 2.22, to read as follows:
Sec. 2.22 Pricing Policy for Transmission Services Provided Under the
Federal Power Act.
(a) The Commission has adopted a Policy Statement on its pricing
policy for transmission services provided under the Federal Power Act.
That Policy Statement can be found at 69 FERC 61,086. The Policy
Statement constitutes a complete description of the Commission's
guidelines for assessing the pricing proposals. Paragraph (b) of this
section is only a brief summary of the Policy Statement.
(b) The Commission endorses transmission pricing flexibility,
consistent with the principles and procedures set forth in the Policy
Statement. It will entertain transmission pricing proposals that do not
conform to the traditional revenue requirement as well as proposals
that conform to the traditional revenue requirement. The Commission
will evaluate ``conforming'' transmission pricing proposals using the
following five principles, described more fully in the Policy
Statement.
(1) Transmission pricing must meet the traditional revenue
requirement.
(2) Transmission pricing must reflect comparability.
(3) Transmission pricing should promote economic efficiency.
(4) Transmission pricing should promote fairness.
(5) Transmission pricing should be practical.
(c) Under these principles, the Commission will also evaluate
``non-conforming'' proposals which do not meet the traditional revenue
requirement, and will require such proposals to conform to the
comparability principle. Non-conforming proposals must include an open
access comparability tariff and will not be allowed to go into effect
prior to review and approval by the Commission under procedures
described in the Policy Statement.
Note: This Appendix will not appear in the Code of Federal
Regulations
Appendix A--Summary of Comments on the Inquiry Concerning the
Commission's Pricing Policy for Transmission Services in Docket No.
RM93-19-000
The request for comments for the inquiry concerning the
Commission's pricing policy for transmission services in Docket No.
RM93-19-000 was issued on June 30, 1993. The date for filing
responses was extended to November 8, 1993 and reply comments to
January 24, 1994. Technical conferences were held on April 8 and 15,
1994. The first day of the conference covered current policy issues.
The second day was devoted to advanced pricing concepts and
implementation issues.
Comments were received from 165 individual commenters. Five
categories of commenters are investor-owned utilities (IOUs, 67
commenters), municipal and cooperative utilities (Muni/Coop, 39
commenters), non-utility generators and independent power producers
(NUGs/IPPs, 15 commenters), Regulatory/Government entities (25
commenters), and Others (19 commenters). A list of the commenters is
at the end of this appendix; it shows the categories under which
their comments are summarized and the acronyms used in this
appendix.
A summary of the comments is provided here. The summary is
organized in the same manner as the two-day conference (current
policy and advanced pricing concepts). The current policy issues are
subdivided into eight comment areas and advanced pricing into four
comment areas as follows:
Current Policy Issues
(1) General Criteria for Transmission Service Pricing
(2) ``And'' Versus ``Or'' Pricing and Related Incentives
(3) Incremental Pricing
(4) Network Service
(5) Ancillary Services
(6) Direction Aspects of Power Flows
(7) Non-Firm Transmission Pricing
(8) Regional Transmission Groups
Advanced Pricing Concepts/Implementation Issues
(1) Alternative Pricing Concepts
(2) Distance/Flow-Based Rates
(3) Contract Path versus Measured Power Flows
(4) Spot Market Pricing
The Commission also received comments on stranded costs in the
course of this Inquiry, but these are not addressed in this Pricing
Policy Statement because stranded cost is the subject of a proposed
rule.\41\
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\41\Docket No. RM94-7-000, Notice of Proposed Rulemaking, June
29, 1994.
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Current Policy Issues
1. General Criteria for Transmission Service Pricing
The first comment area deals with the proposed criteria for
assessing transmission pricing reform. Commenters generally find the
criteria proposed in Staff's Discussion Paper\42\ acceptable.
However, certain criteria are more readily agreed upon than others.
Most commenters uniformly agree that the proposed criteria should:
(1) Be simple to carry out and to administer; (2) promote efficient
use of and investment in the transmission grid; (3) provide
appropriate price signals to transmission customers; and (4) ensure
equity and fairness during and beyond the transition period.
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\42\Staff appendix to Inquiry Concerning the Commission's
Pricing Policy for Transmission Service Provided by Public Utilities
Under the Federal Power Act, FERC States. & Regs. 35,024 (1993).
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Other proposed criteria by commenters include that transmission
pricing policy should:
Ensure system reliability;
Be flexible (i.e., no ``one size fits all'' pricing
methodology) and specifically recognize regional differences;
Encourage the formation of Regional Transmission Groups
(RTGs) and give substantial deference to pricing methodologies
developed by RTGs;
Provide for coordination between state and Federal
pricing policies and encourage collaborative policy development;
Provide for grandfathering of existing contracts and
arrangements when implementing any new policies;
Promote competition in generation;
Unbundle rates for transmission services;
Ensure nondiscriminatory rates, terms, and conditions;
Not allow native load customers to subsidize firm
wheeling;
Give deference to negotiated agreements (with some
commenters adding, where equal bargaining power is involved);
Ensure rate predictability and transparency of rate
derivation; and,
Allow customers an option to have stable prices over
time (although this would not limit parties to fixed rate
contracts).
One criterion emphasized by most commenters is that the
Commission should exercise maximum flexibility in pricing
transmission service. Specifically, many commenters stress that the
Commission should not attempt to rigidly apply a single transmission
pricing methodology in all cases, to all entities, or to all
regions. A general concern raised is that the Commission must
recognize the substantial differences present between customer
groups, utilities, state and local regulatory bodies, and regional
differences. Accordingly, the Commission must resist the temptation
to apply one pricing methodology in all cases.
One common view expressed by many Muni/Coops commenters is that
the industry must move from a structure where multiple transmission
system pricing occurs to a structure where transmission is viewed on
a regional basis in conjunction with the development of large,
regional power markets. Many commenters advocate the regional
transmission grid approach but differ in how the industry and the
Commission should advance toward this goal. Some appear to take a
more cautious approach. For example, some commenters note that the
Commission can only obtain meaningful answers to the questions posed
in its transmission pricing inquiry if it first determines the shape
of the industry it envisions (such as the regional transmission grid
approach or the traditional model based on individually owned and
operated transmission systems). APPA\43\ contends that before
considering changes in traditional transmission pricing, the
Commission should develop and articulate a clear statement of its
``vision'' for the electric industry and specify ``where the
industry is going, how it will get there, likely impediments, and
what steps are necessary for that vision to be fulfilled.'' Many
Muni/Coops commenters also argue that the Commission must first
determine if the benefits of transmission pricing reform will
outweigh the costs of such reform.
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\43\Commenters are referred to by acronym here; acronyms are
defined in a list at the end of this appendix.
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Several Regulatory/Government entities commenters recommend that
the following general principles be included in addition to the
Commission's proposed criteria:
The Commission's pricing policies should reflect
differences between the rights and responsibilities of native load
customers (including retail and wholesale requirements customers)
and other users of the transmission system; any transmission pricing
policy must ensure that native load customers will be held harmless;
and,
The Commission should seek to promote voluntary
resolution of case-specific pricing issues by giving appropriate
deference to consensual agreements produced through arms-length
negotiations involving all affected parties.
NARUC proposes a consultative process to develop complimentary
policies that truly coordinate and render coherent regulation of
transmission service. The general goals include coherence of public
policy, economic efficiency and reliability in electricity markets,
efficiency of processes and decision-making, dialogue between
federal and state decision-makers and appropriate input from
constituent groups and affected parties as necessary. The
Pennsylvania Commission concludes that without careful consideration
of the role of state agencies and their interest in economic and
environmental impacts, bulk power wheeling as envisioned by the
Commission is, and will remain, a theoretical, economic model.
2. ``And'' Versus ``Or'' Pricing and Related Incentives
The ``and'' versus ``or'' issue dominated the pricing comments.
While arguments on all sides of the issue were expressed, the
commenters generally opposed the Commission's current corporate
``or'' policy and alternatively advocated either some form of the
``and'' pricing method or corporate-average embedded cost-based
rates. The positions of the commenters are described below:
The ``And'' Method: Most IOUs, most Regulatory/Government
entities and some Other entities support the ``and'' methodology.
These commenters state that the Commission's ``or'' pricing policy
does not hold the native load customers harmless and violates FPA
section 212(a) (because native load customers and shareholders
subsidize third party wheeling customers). When additional
facilities are needed to serve third party wheeling load, and
incremental (or opportunity) costs are greater than average embedded
cost, native load customers subsidize that service (because no cost
recognition is given to the third party's use of the existing
transmission system, without which the transmission service could
not be provided). Additionally, if incremental expansion cost
related to third party transmission requests are not allowed by
state regulators in retail rates, the transmitting utility will not
be made whole. Finally, the Commission's policy on opportunity cost
which applies the ``higher of'' test over the entire transaction
period instead of an hourly basis precludes opportunity cost
recovery in most cases, sends the wrong hourly price signals to
transmission customers, and is overly burdensome administratively.
The ``Or'' Method: Most NUGs/IPPs commenters agree that the
Commission's current corporate ``or'' policy sends the correct price
signal for third-party transmission (as long as opportunity costs
are ``legitimate and verifiable'' and continue to be capped at
incremental expansion costs). However several commenters oppose
pricing based on opportunity costs (as monopoly rents for a
constrained system).
The Average Embedded Cost Method: Most of the Muni/Coops, some
NUGs/IPPs, and some Other entities generally support the return to
traditional corporate-average embedded cost-based rates. The
majority of the Muni/Coops commenters and some of the Other
commenters oppose both the ``or'' and the ``and'' transmission
pricing methods (as yielding excessive rates and impeding the
competitive generation market that EPAct permits). Such commenters
recommend the traditional policy of charging average embedded cost-
based transmission rates. Many of these commenters argue that a
transmission-dependent utility (TDU) cannot be considered a
``marginal'' customer, subject to incremental and opportunity cost
pricing, because the transmission system was designed to accommodate
the TDU's use and has been paid for proportionally by the TDU.
Furthermore, these commenters argue that applying incremental
pricing to TDUs is anticompetitive and inconsistent with the EPAct
because (1) it forces TDUs to favor power purchases from the host
utility over those from a competing power supplier, and (2) TDUs
compete with the host utility for requirements customers (who are
charged an average embedded cost rate by the host utility).
Commenters views regarding the incentives and disincentives
inherent in corporate ``or'' pricing primarily fall into three basic
positions:
(1) Although groups disagreed among themselves on how to
calculate various cost-based transmission rates, most Muni/Coops,
most Regulatory/Government entities, most NUGs/IPPs, and some others
do not believe in allowing any incentives, or premiums above cost-
based rates, properly calculated. Most of these commenters agreed
that, when a monopoly resource is involved, such incentives amount
to allowing ``monopoly rents.'' Transmission is and will remain a
natural monopoly, therefore, no incentive is needed beyond recovery
of the transmitting utility's prudently-incurred costs and a fair
return on its invested capital. Premiums allow the transmission
monopolist a competitive advantage in the generation market.
Furthermore, there is no need for incentives with the passage of the
transmission provisions of the Energy Policy Act; the legal
requirement to provide transmission service is sufficient incentive.
(2) Most NUGs/IPPs believe the current incentives provided by
the incremental pricing part of the ``or'' policy are appropriate.
However, many of these commenters oppose pricing based on
opportunity costs (as monopoly rents for a constrained system).
(3) Those advocating ``and'' pricing, such as most IOUs and some
Others, believe that further incentives are needed. The current
``or'' policy does not sufficiently compensate utilities for all
costs of providing service, thus effectively requiring native load
customers to subsidize transmission customers. If utilities are
forced to absorb potential cost underrecovery and the risk
associated with the ``or'' pricing methodology, then the rate of
return should be adjusted to reflect greater risks assumed by
engaging in third party wheeling transactions.
3. Incremental Cost Pricing
Under the Commission's current corporate ``or'' policy, third-
party transmission users may be required to pay the incremental cost
of a grid expansion if the incremental cost of the expansion is
greater than corporate-average embedded cost. Such incremental
pricing can be structured in one of two ways--a contract approach in
which each user pays the incremental cost of the upgrade it
occasions, and an average incremental price based on the average
cost of all upgrades to the transmission system for a group of
users.
Most, though not all, commenters believe that contract pricing
is the preferred pricing model. IOUs in particular favor contract
pricing because it provides more certainty that a utility's revenue
requirements are fully recovered. If incremental pricing increases
the risk of less than full revenue recovery, either shareholders or
residual customers will bear the extra risks. Most wholesale
customers also appear to favor contract pricing, though some have
concerns that contract pricing, with different prices for each user,
may result in price discrimination. These commenters suggest that
similarly situated customers should have the same price, but have
different notions of what this would mean.
For many of the difficult practical issues associated with
incremental pricing, there is no consistent position taken by all or
even most members of any interest group that supports incremental
cost pricing. For example, many commenters believe that average
incremental cost pricing gives the wrong price signal to both the
transmission owner and user. These commenters are concerned that the
average incremental cost price does not signal the true cost of the
transmission service. A few commenters argue that this will result
in underbuilding of the transmission system. Others suggest that
this may result in overbuilding, although IOUs in particular doubt
this result, given the difficulties inherent in siting,
certification and construction of new transmission facilities.
Additionally, commenters are split on the issue of
administrative costs and other implementation problems that may
result under each pricing model. Some commenters argue that contract
pricing entails maintaining separate contracting provisions for each
user, with attendant high costs. Other commenters suggest that
average incremental cost pricing is more difficult, given the need
to estimate incremental costs, and the problems associated with
changing average incremental rates as a result of incremental cost
changes. One commenter suggests that it is simply not possible to
reconcile average incremental pricing with an embedded cost
transmission revenue requirement.
Several commenters suggested that it would be appropriate to
allow utilities some flexibility to adopt either incremental cost
pricing approach. The challenge for the Commission would be to
determine under what conditions such flexibility would be warranted,
in order to protect both the third-party transmission users and the
remaining wholesale and retail customers from being charged for
inappropriate costs. Other commenters suggest that some
experimentation may be in order. If the Commission chooses to allow
such experimentation, it may learn a great deal about the magnitude
of the practical problems, as well as potential solutions for those
problems.
4. Network Service
The Staff Discussion Paper defined network service as allowing
the user to vary its schedule and points of delivery and receipt
without paying additional charges for each change. Commenters were
asked to discuss the reasonableness of this definition and to
provide recommendations on pricing network service. Most IOUs assert
that utilities cannot provide third party transmission users with
unlimited flexibility in choosing and switching points of receipt
and delivery. Unless the transmission customer specifies the points
of receipt and delivery, the nature of the generation, and the loads
to be served, the transmitting utility will have no way to determine
the impact of the proposed network arrangement on its system in
terms of either reliability or cost. Unlimited flexibility could
require transmission upgrades and make long term planning more
difficult (with the potential for overbuilding). If network service
is to include unlimited scheduling flexibility, it should be
considered a premium service (priced higher than point-to-point
service) since it requires higher transmission capacity margins to
ensure reliability.
Most Muni/Coops, Regulatory/Government entities, NUGs/IPPs and
some Other commenters agree with the Commission's definition of
network service. Most Muni/Coops, NUGs/IPPs and some Other
commenters insist that network service should be priced on an
average embedded cost basis (with no non-cost-based network rate
premiums or percentage adders). These commenters argue that such
premiums would place network customers at a permanent competitive
disadvantage in obtaining economical generation sources and in
generation sales, compared to the transmitting utility. Many
commenters agree that network access should not be totally flexible,
nor be unduly rigid with reservation requirements and excessively
advanced scheduling requirements; rather, they believe it should be
subject to the same conditions faced by the transmitting utility,
and provide access to transmission on an ``as if owned'' basis.
APPA asserts that it is not aware of any party that is seeking
network access without regard to the control area utility's own
transmission needs, or that is requesting network service with total
flexibility, i.e., no scheduling or backup requirements. APPA adds
that it agrees with EEI on two points concerning utilities receiving
network service: ``they should state in planning models the sources
of power that most probably will be used to serve loads, and they
should schedule generation to serve load with the transmitting
utility.''
Regulatory/Government entities generally agree that accurate
pricing of network service will depend on the nature of the network
and any revenue pooling between transmission providers. Therefore,
Regulatory/Government entities urge the Commission to be flexible
and not mandate any particular method for pricing network service.
5. Ancillary Services
The Staff Discussion Paper gave examples of ancillary services
and requested comments on other examples (including how such
services should be priced). Most IOUs recommend that unless third
party customers obtain ancillary services elsewhere, they should
compensate the wheeling utility for the services provided to prevent
the native load customers from subsidizing these services. IOUs note
that as bulk power markets are becoming more competitive and
independent power producers are supplying ever increasing amounts of
generation, these support type services that were once provided on a
reciprocal basis among utilities are not being provided by many
suppliers because they are either unwilling or unable to provide
such service.
One of the main concerns of the Muni/Coops commenters is that
costs associated with ancillary services should not already be
included in the average cost-based transmission rate. Additionally,
several commenters insist that transmission customers should be
given the option to provide such services themselves, or obtain them
from other utilities, and receive full credit. These commenters also
express concern regarding discriminatory pricing. Such commenters
urge that any charges for ancillary services assessed to a
transmission customer should be the same as the costs faced by the
transmitting utility for the same service.
NUGs/IPPs, Regulatory/Government entities and Others generally
did not address this issue.
Other claimed ancillary services include: Backup and Standby
Service; Loss Service; Redispatch Costs; Control Center Service;
Emergency Services; fast starts, ``BlackStart'' capability (starting
up a generating station with no external power supply), regulation,
and stability.
Graves, et al. proposed that ancillary services could be
provided by an independent entity, which they call a ``Poolco''
(e.g., an existing power pool, an RTG, NERC subregion, or consortium
of independent generators). Their version of a Poolco would not
participate directly in real power MW brokerage or energy supply;
rather, it would own and operate a relatively small collection of
generation and flow control assets sufficient to assure the
integrity of the system, relying on tieline flows, voltage
measurements at a few key load centers, and forecast control-area
load changes (over the next few hours).
6. Direction Aspects of Power Flows
The power flows caused by a transmission transaction may be
either with, or counter to, the prevailing flows. The incremental
effects of transmission transactions may also raise issues with
respect to the use of multiple parallel paths and the incremental
effects on transmission losses.
A. Directional Flows
Most commenters (most IOUs, some Muni/Coops, and some
Regulatory/Government entities) suggest that charges should be
applied for all power flows on a system (regardless of direction).
Several commenters indicate that reverse flows exist only under some
system conditions and that changes in transmission system
configuration (due to line outages) and changes in generating unit
dispatch, may eliminate any reverse flows. Such commenters also
claim that all transmission elements support all power flows.
Accordingly, reverse flows should only be credited if they provide a
direct economic benefit to the utility.
Other commenters (some Muni/Coops, some Regulatory/Government
entities, and most Others) argue that it is important for the
Commission to adopt a transmission pricing method which recognizes
flow direction and discounts transmission service which ``unloads''
the system and helps to relieve constrained transmission lines.
These commenters suggest that this type of pricing signal encourages
the most efficient use of the transmission system.
B. Loop Flows
Few comments on this issue were received from Muni/Coops, NUGs/
IPPs, Regulatory/Government entities and Others. There did not
appear to be any consensus among the IOUs on the best method to
address loop flow problems.
Southern Companies indicates that loop flows were often short-
lived and were viewed as part of the normal interconnected
operations among utilities. It was once commonly viewed that loop
flows on one utility's system would most likely be offset by loop
flows on its neighboring systems. In instances where the flows were
a problem, negotiated solutions were reached. LG&E notes that bulk
power transactions were once predominantly multi-directional and
covered shorter distances so that transactions evened out over time.
However, in today's marketplace transactions are more numerous,
over longer distances, and unidirectional. As a result, loop flows
do not even out over time. In the new competitive environment,
Southern Companies, AEP and Northern States claim the situation has
changed. In the emerging bulk power market, many more long term firm
transactions in a single direction are contemplated which will more
adversely impact flows over interconnected systems. These commenters
state that it also may be more difficult in a competitive
environment to negotiate solutions to parallel flow problems.
Consumers believes that uncertainty about loop-flow compensation may
be a significant potential barrier to the more rapid development of
competition among new generators.
C. Losses
Many commenters (some IOUs, most Muni/Coops, some Others) argue
that losses vary in proportion to the distance over which the energy
is moved, and accordingly, contend that incremental losses send a
more appropriate price signal to the customer (by more closely
linking cost causation and cost recovery). Tabors claims that
efficiency requires pricing losses at the margin, which can be
accomplished using load flow calculations and Optimal Power Flow
modeling techniques. On the other hand, many commenters recommend
average system line losses. Several of these commenters insist that
they should be charged for line losses on the same cost basis that
the transmitting owners use for their own dispatch and charge their
native load customers.
7. Non-Firm Transmission Pricing
A fundamental issue of non-firm transmission service pricing is
whether or not a contribution to capital costs over and above the
variable cost of transmission (losses and opportunity costs) should
be made for non-firm service. One view is that users of non-firm
service should not pay for capacity costs since capacity is not
built for them and their service can always be interrupted. On the
other end of the spectrum are those that advocate a contribution of
up to 100 percent of fixed costs, since firm customers need to be
compensated for the use of the transmission system that they support
in its entirety.
Most IOUs indicate that non-firm users of the transmission
system should contribute to the capital costs of the system. They
believe the Commission should rely on its historical precedent,
which allows a contribution of up to 100 percent of fixed costs for
non-firm service with the revenues being credited to native load
customers. Some believe the shareholders should receive some of the
revenues from non-firm transactions. Other commenters suggest
minimal regulation of non-firm transactions as long as the price
does not exceed a cap equal to its fully allocated transmission
costs.
Many of the Muni/Coops commenters state that there are no fixed
costs associated with providing non-firm transmission services and
note that groups in different parts of the country (e.g., PJM,
NEPOOL, MAPP and ERCOT) do not include contributions to fixed costs
in non-firm transmission pricing. Many commenters believe that no
demand charges for non-firm transmission are necessary and argue
that such demand charges may have a negative impact on the
efficiencies of the economy energy market for short term
transactions. For example, Consumer Working Group recommends:
Limiting non-firm rates to real costs (i.e. losses) would
eliminate the artificial dead zone created by the incentive
transmission rates now allowed. By granting all market participants
(and not just transmission owners) access at cost to non-firm
transactions, all consumers would benefit from increased
coordination. Such nondiscriminatory, cost-based pricing of non-firm
transmission would serve the EPAct's purpose of stimulating
competition in bulk power markets and would promote economically
efficient generation of electricity as expressly mandated by Section
212(a). (Consumer Working Group Reply at 21)
8. Regional Transmission Groups
All segments of the industry supported the Commission's
encouragement of the development of such groups. Many commenters
believe that RTGs represent the best method available to deal with
the difficult transmission pricing issues presented in Staff's
Discussion Paper. Some commenters cautioned that to be successful,
RTGs must be certified by the Commission to ensure proper
representation of all groups within the electric utility industry.
Many commenters anticipate RTGs will facilitate coordinated regional
planning, regional measurement of power flows and regional
methodologies to determine the price of any firm wheeling
transaction within the region. The information available on a
regional basis will allow planning to alleviate current and future
transmission constraints within the region as well as send a clear
price signal to third party customers requesting service. RTG's will
also provide information as to what transmission capacity is
available and the need for any transmission enhancements within the
region to accommodate the requested transaction.
Advanced Pricing Concepts/Implementation Issues
1. Alternative Pricing Concepts
Numerous commenters proposed alternative pricing methods, other
than those pricing methods normally permitted by this Commission.
The methodologies advanced by these commenters varied from
conceptual ideas to detailed formulas. Certain concepts and methods
were advocated by more than one and in some cases several
commenters, including:
Combinations of, or hybrids between, the ``or'' and the
``and'' policies, many of which advocated recovery of all
incremental costs and some contribution (but not necessarily 100%)
to average embedded system costs.
Variations of recovering strictly incremental or
marginal cost pricing; i.e., rates based on long-run incremental
cost pricing for long-term firm transmission service and short-run
marginal costs for other transactions. Another commenter proposed
short-run marginal costs for transactions not requiring upgrades.
Numerous proposals for a single transmission owner and
for regional pricing, planning and operating approaches; for
example: (1) The forced divestiture of all utilities' transmission
assets and formation of a single transmission owning national grid
company or ``gridco''; (2) joint ownership, operation and pricing of
all transmission within an established region with all transmission
users obtaining load ratio shares of the regional grid and paying on
an average embedded load ratio basis; (3) a proposal simply to price
transmission in a region as if there were a single transmission
owner; and (4) many suggestions for the Commission to further
examine the companies formed in Norway, Sweden, New Zealand,
Victoria (Australia), India, Argentina, England and Wales.
Establishing a secondary market in transmission
rights--transmission purchasers having the capacity to contractually
broker, resell, trade, partially assign, or assign firm purchase
entitlements as they choose. Capacity trading will provide for the
repackaging of capacity rights to fit market needs, thereby creating
a market mechanism to ``price'' and ``clear'' transmission services
as a commodity.
Numerous proposals advocating that the Commission
require the unbundling of rates for transmission and sales services.
Unbundling would require transmission owners to include a separate
(transparent) transmission charge in any use of the utility's
transmission system for the delivery of power in the wholesale
market, including that utility's own wholesale sales. Transmission
terms and conditions should be the same for all wholesale
transactions, regardless of whether the seller is the owner of the
transmission facilities used for the transaction.
2. Distance/Flow-Based Rates
Alternatives to postage stamp rates would make rates sensitive
to the transmission distance involved in providing the service.
Alternatives suggested include various ``MW-mile'' approaches and
other methods based on load flows (such load flow methods can also
treat issues involving multiple parallel paths and transmission
losses associated with particular transmission transactions).
Commenters' support is split between distance-based pricing and
postage stamp rates.
Regulatory/Government commenters express a clear preference for
distance-sensitive rates (over postage stamp rates). Most
Regulatory/Government entities, some IOUs, some NUGs/IPPs, and some
Others argue that distance-based rates would compensate the
transmitter for increased transmission costs as more of its system
is used. This encourages more efficient use of the transmission
system. Where more miles of the transmission system are utilized,
distance-sensitive rates reflect the proper cost causation. Several
commenters believe that simplified distance-sensitive pricing
methods, such as some MW-mile methods, used in conjunction with
approaches such as zonal pricing that reflects system constraints,
would be appropriate. Numerous commenters advocating distance-based
rates recommend zonal pricing as a compromise between the
administrative simplicity of postage stamp rates and more
appropriate price signals of certain distance-based rate methods.
Most Muni/Coops, some IOUs, and some NUGs/IPPs support postage
stamp rates and criticize distance-sensitive pricing due to its
dependence upon power flow studies involving a base and a change
case. Many commenters note that power flows on a transmission system
are in constant change, thereby creating a very large number of
possible system parameters that could be included in load flow
analyses and therefore requiring many simplifying assumptions.
Consequently, any attempt to derive a normal base case power flow on
which to model an incremental power flow would be flawed and
unreliable, particularly for individual utilities located in heavily
interconnected networks. Therefore, these commenters prefer the
administrative convenience of postage stamp rates over the
complexity and questionable accuracy of distance-sensitive rates
based on power flow studies.
3. Contract Path Versus Measured Power Flows
The mismatch between the contract path for a transaction and the
actual flows creates pricing and equity concerns. Utilities are
split regionally on whether to adopt loop flow, or parallel path,
pricing reform or retain contract path pricing. Most Western
utilities favor retaining contract path pricing. Western utilities
maintain that the topology of the WSCC makes it well suited to the
use of phase shifters to control the loop flow problem. In addition,
the development of Flexible AC Transmission technology may provide
additional devices to augment existing control strategies.
Many utilities in the Midwest and the East favor adopting loop
flow pricing because over time contract path pricing has left many
systems uncompensated for parallel flows. These utilities argue that
contract path pricing is outmoded because (1) transmission services
have become long-term single direction transactions, (2) many new
market entities do not own transmission so that reciprocity is not
possible, and (3) negotiated solutions are less possible as
competition expands.
Many utilities in favor of loop flow pricing are concerned that
the associated transition costs are formidable. Parallel flows
constantly change with changes in the dispatch of generation. In
addition, some utilities urge the development of RTGs first before
implementing loop flow pricing. In fact, there is general agreement
that RTGs are an appropriate institution for addressing many of the
industry's problems including pricing issues and the siting and
construction of transmission facilities.
While there is widespread dissatisfaction with contract path
pricing outside of the West, there is considerable uncertainty about
how to address the parallel flow problem effectively. Many parties
believe that contract path pricing and loop flow pricing can be
combined to address the problem, while other parties believe that
these two methods are incompatible. Still other parties offer an
array of variations on the contract path pricing and loop flow
pricing methods. For example, Hogan's ``contract network'' approach
and PacifiCorp's proposal are variations on the contract path
pricing method. The GAPP experiment, which the Interregional
Transmission Coordination Forum stresses as the way to identify the
pricing method to compensate for parallel flows, is a preliminary
type of loop flow pricing. The Texas Planned Capacity Wheeling
Service and Southern Company's Transmission Cost Actual Path Pricing
are also examples of loop flow pricing. Finally, many parties argue
that alternatives to contract path pricing should be pursued on a
voluntary basis.
4. Spot Pricing for Non-firm Transmission
Few commenters express outright opposition to spot pricing, but
most advocate a cautious approach to implementation. Those in the
latter category comprise a diverse group of IOUs (including EEI),
coops, state commissions and industrial groups. Many suggest that
spot pricing schemes should continue to be studied, but not
considered for implementation at this time. Some encourage the
Commission to conduct experiments similar to the Southwest Bulk
Power Experiment and the WSPP.
Those opposed to spot pricing generally believe that the
benefits are not worth the costs. Some argue that the successful
implementation of spot pricing for transmission requires a
competitive market in generation that does not now exist. However,
some commenters that see promise in spot pricing argue that the
necessary market institutions and technology exist today. They cite
the operation of tight power pools, electronic bulletin boards, and
the WSCC experiment as evidence of this fact.
Some commenters argue that the ``up to'' transmission rates that
many utilities now use for non-firm transmission service effectively
approximate spot transmission pricing. However, others believe that
rate design for spot transmission pricing raises a number of
difficult issues, such as the use of one-part versus two-part rates,
and the appropriate definition of the cost of transmission service.
Several commenters offer highly developed policy proposals or
technical models for use in implementing spot pricing. In
particular, Hogan and Putnam believe that all participants in the
power market should have access to economic dispatch with marginal
cost pricing. Hogan argues that transmission rights cannot be built
on the traditional wheeling model that assumes that specific power
moves to specific customers. He claims that only by stepping away
from such misleading assumptions can the Commission design a set of
pricing and access reforms that are consistent with the underlying
economics and will support an efficient competitive electricity
market.
List of Commenters in the Transmission Pricing Policy Inquiry
The following parities filed either initial or reply comments.
Acronyms used in this appendix are defined here.
Investor-Owned Electric Utilities and Associations
1. Allegheny Power Service Corporation
2. American Electric Power System Companies (AEP)
3. Arizona Public Service Company
4. Association of Electric Companies of Texas
5. Atlantic City Electric Company
6. Bangor Hydro-Electric Company
7. Carolina Power and Light Company
8. Centerior Energy Corporation
9. Central and South West Services, Inc.
10. Central Illinois Public Service Company
11. Central Louisiana Electric Company
12. Commonwealth Edison Company
13. Consumers Power Company/CMS Energy (Consumers)
14. Dayton Power and Light Company
15. Detroit Edison Company
16. Dominion Resources, Inc.
17. Duke Power Company
18. Duquesne Light Company
19. Edison Electric Institute (EEI)
20. Entergy Services, Inc.
21. Florida Power Corporation
22. Florida Power Corporation, Wisconsin Electric Power Company, and
Wisconsin Public Service Corporation
23. Houston Lighting & Power Company
24. Idaho Power Company
25. Indianapolis Power & Light Company
26. Iowa-Illinois Gas and Electric Company
27. LG&E Energy Corp.
28. Long Island Lighting Company
29. Louisville Gas and Electric Company
30. Midwest Power Systems, Inc.
31. Montana Power Company
32. New England Power Service
33. New York State Electric & Gas Corporation
34. Niagara Mohawk Power Corporation (Niagara Mohawk)
35. Northeast Utilities System Companies
36. Northern States Power Company (Northern States)
37. Ohio Edison Company
38. Otter Tail Power Company
39. PacifiCorp
40. Pacific Gas and Electric Company
41. Pennsylvania-New Jersey-Maryland Interconnection
42. Pennsylvania Power & Light Company
43. Philadelphia Electric Company
44. Portland General Electric Company
45. PSI Energy Inc. and Cincinnati Gas & Electric Company
46. Public Service Company of Colorado
47. Public Service Company of New Mexico
48. Public Service Electric and Gas Company
49. Puget Sound Power & Light Company
50. San Diego Gas & Electric Company
51. Sierra Pacific Power Company
52. South Carolina Electric & Gas Company
53. Southern California Edison Company
54. Southern California Gas Company
55. Southern Companies
56. Southwestern Public Service Company
57. Tampa Electric Company
58. Texas Utilities Electric Company
59. Tucson Electric Power Company
60. Union Electric Company
61. United Illuminating Company
62. Unitil Power Corporation
63. Utility Working Group
64. Washington Water Power Company
65. Western Resources, Inc. and Kansas Gas and Electric Company
66. Wisconsin Electric Power Company
67. Wisconsin Public Service Corporation
Municipals, Cooperatives and Government-Owned Electric Utilities
and Related Associations
1. Alabama Electric Cooperative, Inc. and South Mississippi
Electric Power Association
2. Allegheny Electric Cooperative, Inc.
3. American Public Power Association (APPA)
4. Arizona Power Authority
5. Associated Electric Cooperative, Inc.
6. Basin Electric Power Cooperative
7. Bonneville Power Administration
8. California Department of Water Resources
9. City of Anaheim, California
10. City of Vernon, California
11. Colorado Association of Municipal Utilities
12. Colorado Joint Transmission Principles Participants
13. Consumer Working Group
14. East Kentucky Power Cooperative, Inc., Saluda River Electric
Cooperative, Inc., and Wolverine Power Supply Cooperative
15. East Texas Cooperatives
16. Florida Municipal Power Agency, Michigan Municipal Cooperative
Group and Wolverine Power Supply Cooperative
17. Indiana Municipal Power Agency
18. Irrigation and Electrical Districts Association of Arizona
19. Large Public Power Council
20. Lincoln Electric System
21. Massachusetts Municipal Power Systems
22. Missouri Basin Municipal Power Agency
23. Municipal Electric Authority of Georgia
24. National Rural Electric Cooperative Association
25. Northern California Power Agency
26. Oglethorpe Power Corporation
27. Old Dominion Electric Cooperative, Inc.
28. Public Generating Pool
29. Sacramento Municipal Utility District
30. South Texas Electric Cooperative, Inc. and Medina Electric
Cooperative, Inc.
31. Tennessee Valley Authority
32. Transmission Access Policy Study Group
33. Transmission Agency of Northern California
34. Transmission Dependent Systems
35. Turlock Irrigation District
36. Utah Associated Municipal Power Systems
37. Wabash Valley Power Association, Inc.
38. Wisconsin Public Power, Inc. SYSTEM
39. Wisconsin Wholesale Customers
Non-Traditional Utility Generators (NUGs, IPPs, EWGs and Qfs),
Power Marketers Foreign Entities and Related Associations
1. American Wind Energy Association
2. British Columbia Power Exchange Corporation (POWEREX)
3. California Independent Energy Producers Association
4. Electric Generation Association
5. Enron Power Marketing, Inc.
6. Fuel Managers Association
7. Geothermal Resources Association
8. Hydro-Quebec
9. InterCoast Power Marketing Company
10. Kvaener Energy Development Inc. and Citizens Power & Light Co.
11. LG&E Power, Inc.
12. National Independent Energy Producers
13. National Power Plc
14. Ontario Hydro
15. Torco Energy Marketing, Inc.
State Regulatory Commissions and Other Government Agencies
1. Alabama Public Service Commission
2. California Energy Commission
3. California Public Utilities Commission
4. Florida Public Service Commission
5. Georgia Public Service Commission
6. Idaho Public Utilities Commission
7. Illinois Commerce Commission
8. Indiana Utility Regulatory Commission
9. Kansas Corporation Commission
10. Maine Public Utilities Commission and the Vermont Department of
Public Service
11. Massachusetts Department of Public Utilities
12. Michigan Public Service Commission
13. National Association of Regulatory Utility Commissioners (NARUC)
14. Nevada Public Service Commission
15. New York State Department of Public Service
16. Ohio Public Utilities Commission the Ohio Sitting Board
17. Pennsylvania Public Utility Commission
18. Sharp, The Hon. Philip R., Chairman, Subcommittee on Energy and
Power
19. Texas Public Utility Commission
20. United States Department of Energy
21. United States Department of Justice
22. Virginia State Corporation Commission
23. Wallop, The Hon. Malcolm, Senate Committee on Energy and Natural
Resources
24. Washington State Energy Office
25. Wisconsin Public Service Commission
Others
1. American Forest and Paper Association (American Forest & Paper)
2. Burns, Robert E.
3. Committee on Regional Electric Power Cooperation
4. Direct Electric Inc. (Direct Electric)
5. Drazen-Brubaker & Associates, Inc.
6. Electricity Consumers Resource Council, the American Iron and
Steel Institute and the Chemical Manufacturers Association
7. Electric Power Research Institute
8. Ernst & Young Utilities Consulting/Frederick L. McCoy
9. Hogan, William W. (Hogan)
10. Incentives Research, Inc., and Massachusetts Institute of
Technology (Graves, et al.)
11. Institute of Electrical and Electronic Engineers
12. Interregional Transmission Coordination Forum
13. Joint Consumer Advocates
14. Lively, Mark B.
15. New York Mercantile Exchange
16. Ohio Office of the Consumers' Counsel
17. Putnam, Hayes & Bartlett, Inc. (Putnam)
18. SASY Inc.
19. Tabors Caramanis & Associates (Tabors)
[FR Doc. 94-27091 Filed 11-2-94; 8:45 am]
BILLING CODE 6717-01-P