[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]


[[Page Unknown]]

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

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

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

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

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

    \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 ________.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

    \38\See Pacific Gas Transmission, 66 FERC 61,384, reh'g denied, 
67 FERC 61,247 (1994), reh'g pending.
---------------------------------------------------------------------------

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

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

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

    \40\See Alternative Power Pooling Institutions under the Federal 
Power Act, Notice of Inquiry, FERC Stats. and Regs. ________.
---------------------------------------------------------------------------

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

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

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

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

    \43\Commenters are referred to by acronym here; acronyms are 
defined in a list at the end of this appendix.
---------------------------------------------------------------------------

    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